10-Q

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017

OR

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from  to  .

Commission File Number 001-33147

Sanchez Midstream Partners LP

(Exact name of registrant as specified in its charter)

Delaware	11-3742489
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
1000 Main Street, Suite 3000 Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

(713) 783-8000

(Registrant’s Telephone Number, Including Area Code)

(Former name, former address and former fiscal year, if changed since last report)

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 pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐ 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or 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.

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 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   ☒ 

Common units outstanding as of November 10, 2017: Approximately 14,778,192 units.

TABLE OF CONTENTS

		Page
PART I—Financial Information		5
Item 1.	Financial Statements	5
	Condensed Consolidated Statements of Operations (Unaudited)	5
	Condensed Consolidated Balance Sheets (Unaudited)	6
	Condensed Consolidated Statements of Cash Flows (Unaudited)	7
	Condensed Consolidated Statements of Changes in Partners’ Capital (Unaudited)	8
	Notes to Condensed Consolidated Financial Statements (Unaudited)	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	45
PART II—Other Information		46
Item 1.	Legal Proceedings	46
Item1A.	Risk Factors	46
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3.	Defaults Upon Senior Securities	46
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	46
Signatures		48

2

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements” as defined by the Securities and Exchange Commission that are subject to a number of risks and uncertainties, many of which are beyond our control.  These statements may include discussions about our business strategy; acquisition strategy; financing strategy; ability to make, maintain and grow distributions; the ability of our customers to meet their drilling and development plans on a timely basis or at all and perform under gathering, processing and other agreements; future operating results; future capital expenditures; and plans, objectives, expectations, forecasts, outlook and intentions. All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Part I, Item 2. and other items within this Quarterly Report on Form 10-Q. 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 Quarterly Report on Form 10-Q are largely based on our expectations, which reflect estimates and assumptions made by the management of our general partner. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate.

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

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

· our ability to make, maintain and grow distributions;

· the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids (“NGLs”), natural gas and related commodities;

· 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 which may affect our throughput rates and revenues;

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

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

· competition in the oil and natural gas industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

· 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;

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

· our ability to compete with other companies in the oil and natural gas industry;

· the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

· the extent to which our crude oil and natural gas properties operated by others are operated successfully and economically;

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· the use of competing energy sources and the development of alternative energy sources;

· unexpected results of litigation filed against us;

· disruptions due to extreme weather conditions, such as extreme rainfall, hurricanes or tornadoes;

· the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage; and

· the other factors described under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and elsewhere in this Quarterly Report on Form 10‑Q and in our other public filings with the Securities and Exchange Commission.

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

4

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements  

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Operations  

(In thousands, except unit data)

(Unaudited)

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Revenues
Natural gas sales	$	787	$	4,434	$	5,818	$	8,709
Oil sales		3,061		2,159		22,520		4,746
Natural gas liquids sales		514		264		1,473		784
Gathering and transportation sales		14,234		12,997		39,621		41,130
Total revenues		18,596		19,854		69,432		55,369
Expenses:
Operating expenses:
Lease operating expenses		1,735		2,767		10,599		11,918
Transportation operating expenses		2,661		3,111		8,989		9,179
Cost of sales		—		99		77		292
Production taxes		340		290		1,166		837
General and administrative		5,614		6,286		17,576		16,983
Unit-based compensation expense		631		90		1,951		1,619
Loss (gain) on sale of assets		(2,546)		219		(2,546)		219
Depreciation, depletion and amortization		6,899		7,507		28,017		20,824
Asset impairments		—		—		4,688		1,309
Accretion expense		149		271		647		901
Total operating expenses		15,483		20,640		71,164		64,081
Other (income) expense
Interest expense, net		2,215		1,543		5,994		3,545
Gain on embedded derivatives		—		(30,012)		—		(43,204)
Earnings from equity investments		(2,873)		(1,124)		(4,397)		(1,136)
Other income		—		—		—		(49)
Total other (income) expenses		(658)		(29,593)		1,597		(40,844)
Total (income) expenses		14,825		(8,953)		72,761		23,237
Income (loss) before income taxes		3,771		28,807		(3,329)		32,132
Income tax expense		—		—		—		—
Net income (loss)		3,771		28,807		(3,329)		32,132
Less:
Preferred unit distributions paid in common units		—		—		(2,625)		—
Preferred unit distributions		(8,750)		(12,250)		(24,500)		(29,750)
Preferred unit amortization		(463)		(6,608)		(1,300)		(20,379)
Net income (loss) attributable to common unitholders	$	(5,442)	$	9,949	$	(31,754)	$	(17,997)
Net income (loss) per unit
Net income (loss) per unit
Common units - Basic	$	(0.38)	$	2.49	$	(2.29)	$	(5.06)
Common units - Diluted	$	(0.38)	$	1.21	$	(2.29)	$	(5.06)
Weighted Average Units Outstanding
Common units - Basic		14,313,999		3,998,209		13,888,057		3,556,675
Common units - Diluted		14,313,999		23,771,370		13,888,057		3,556,675

See accompanying notes to condensed consolidated financial statements.

5

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Balance Sheets

(In thousands, except unit data)

	September 30,		December 31,
ASSETS	2017		2016
		(Unaudited)
Current assets
Cash and cash equivalents	$	367	$	957
Accounts receivable		731		1,212
Accounts receivable - related entities		6,729		5,987
Prepaid expenses		2,389		2,041
Fair value of derivative instruments		2,114		4,568
Total current assets		12,330		14,765
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)		200,471		758,913
Gathering and transportation assets		183,681		152,209
Material and supplies		—		1,056
Less: accumulated depreciation, depletion, amortization and impairment		(162,403)		(689,358)
Oil and natural gas properties and equipment, net		221,749		222,820
Other assets
Intangible assets, net		175,530		185,766
Fair value of derivative instruments		3,187		3,964
Equity investments		120,303		111,614
Other non-current assets		585		776
Total assets	$	533,684	$	539,705
LIABILITIES AND PARTNERS' CAPITAL
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	364	$	951
Accounts payable and accrued liabilities - related entities		6,482		7,046
Royalties payable		371		706
Fair value of derivative instruments		16		740
Total current liabilities		7,233		9,443
Other liabilities
Asset retirement obligation		7,796		13,579
Long-term debt, net of debt issuance costs		187,686		151,322
Fair value of derivative instruments		22		1,356
Other liabilities		4,049		4,270
Total other liabilities		199,553		170,527
Total liabilities		206,786		179,970
Commitments and contingencies (See Note 11)
Mezzanine equity
Class B preferred units, 31,000,887 and 29,296,441 units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively		343,416		342,991
Partners' capital (deficit)
Common units, 14,773,192 and 13,447,749 units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively		(16,518)		16,744
Total partners' capital (deficit)		(16,518)		16,744
Total liabilities and partners' capital	$	533,684	$	539,705

See accompanying notes to condensed consolidated financial statements.

6

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows 

(In thousands)

(unaudited)

	Nine Months Ended
	September 30,
	2017		2016
Cash flows from operating activities:
Net income (loss)	$	(3,329)	$	32,132
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization		17,813		11,341
Amortization of debt issuance costs		391		377
Revisions to asset retirement obligation included in DD&A		—		(862)
Asset impairments		4,688		1,309
Accretion expense		647		901
Distributions from equity investments		5,329		750
Equity earnings in affiliate		(4,397)		(1,135)
Bad debt expense		—		35
(Gain)/loss from disposition of property and equipment		(2,386)		210
Total mark-to-market on commodity derivative contracts		(7,584)		2,664
Cash settlements on commodity derivative contracts		5,093		17,361
Cash settlements on terminated commodity derivatives		3,602		3,197
Premiums paid on derivative contracts		—		(3,197)
Unit-based compensation expense		2,646		2,042
Gain on embedded derivative		—		(43,204)
Amortization of intangible assets		10,204		10,345
Costs for plug and abandon activities		(46)		(142)
Changes in Operating Assets and Liabilities:
Accounts receivable		159		872
Accounts receivable - related entities		(1,042)		(5,025)
Prepaid expenses		(348)		(1,505)
Other assets		124		682
Accounts payable and accrued liabilities		6,416		(962)
Accounts payable and accrued liabilities - related entities		(1,033)		2,760
Royalties payable		(301)		(112)
Net cash provided by operating activities		36,646		30,834
Cash flows from investing activities:
Development of oil and natural gas properties		(148)		(2,706)
Proceeds from sale of oil and natural gas properties		5,510		38
Final settlement of oil and natural gas properties acquisition		1,468		—
Development of gathering and transportation assets		(29,058)		—
Purchases of equity investments		(10,380)		(40,002)
Net cash used in investing activities		(32,608)		(42,670)
Cash flows from financing activities:
Payments for offering costs		(611)		(226)
Proceeds from issuance of debt		45,500		39,000
Repayment of borrowings		(9,500)		—
Proceeds from issuance of preferred units		—		(87)
Repurchase of common units under repurchase program		—		(2,948)
Units tendered by employees for tax withholdings		—		(140)
Distributions to common unitholders		(18,530)		(4,815)
Proceeds from issuance of common units		1,290		—
Class B preferred unit cash distributions		(22,750)		(24,918)
Debt issuance costs		(27)		—
Net cash provided by (used in) financing activities		(4,628)		5,866
Net decrease in cash and cash equivalents		(590)		(5,970)
Cash and cash equivalents, beginning of period		957		6,571
Cash and cash equivalents, end of period	$	367	$	601
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	$	2,414	$	1,562
Change in asset retirement obligations	$	198	$	—
Cash paid during the period for interest	$	5,494	$	3,085
Earnout liability	$	221	$	—

See accompanying notes to condensed consolidated financial statements.

7

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Changes in Partners’ Capital for the Nine Months Ended September 30, 2017

(In thousands, except unit data)

(Unaudited)

	Class A Preferred Units			Common Units			Total
	Units	Amount		Units	Amount		Capital
Partners' Capital (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	—		—	212,481		2,648		2,648
Issuance of common units, net of offering costs of $0.6 million	—		—	719,671		9,124		9,124
Cash distributions to common unit holders	—		—	—		(18,530)		(18,530)
Common units issued as Class B Preferred distributions	—		—	393,291		5,250		5,250
Distributions - Class B preferred units	—		—	—		(28,425)		(28,425)
Net loss	—		—	—		(3,329)		(3,329)
Partners' Capital (Deficit), September 30, 2017	—	$	—	14,773,192	$	(16,518)	$	(16,518)

See accompanying notes to condensed consolidated financial statements.

8

SANCHEZ MIDSTREAM PARTNERS LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND BUSINESS

Organization

Sanchez Midstream Partners LP, a Delaware limited partnership, (together with our consolidated subsidiaries, “SNMP,” “we,” “us,” “our” or the “Partnership”) (formerly Sanchez Production Partners LP), is a growth oriented publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and production assets in North America. SNMP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). We have entered into a shared services agreement (the “Services Agreement”) with SP Holdings, LLC (the “Manager”), the sole member of our general partner, pursuant to which the Manager provides services that the Partnership requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. On March 6, 2015, the Company’s unitholders approved the conversion of Sanchez Production Partners LLC to a Delaware limited partnership and the name was changed to Sanchez Production Partners LP. On June 2, 2017, Sanchez Production Partners LP changed its name to Sanchez Midstream Partners LP. Manager owns the general partner of SNMP and all of SNMP’s incentive distribution rights. Our common units are currently listed on the NYSE American under the symbol “SNMP,” and were traded under the symbol “SPP” prior to our recent name change.

Historically, our operations have consisted of the production of proved reserves located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana. In October 2015, we consummated the acquisition of midstream assets in the Eagle Ford Shale from Sanchez Energy Corporation (“Sanchez Energy”) and entered into a 15-year gathering and processing agreement with Sanchez Energy. We also commenced a process to sell our production assets in the Mid-Continent region.  In July 2016, we sold a portion of our production assets in the Mid-Continent region and acquired a 50% equity interest in Carnero Gathering, LLC (“Carnero Gathering”). In November 2016, we completed a public offering of approximately 6,745,107 common units (which includes exercise of the underwriters’ option to purchase 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses.  Concurrent with the public offering, we completed a private placement of 2,272,727 common units representing limited partner interests for net proceeds of approximately $25.0 million. The combined proceeds were used to close the acquisition of a 50% equity interest in Carnero Processing, LLC (“Carnero Processing”) and the acquisition of working interests in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas and escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas. In July 2017, we sold our equity interests in the entities that owned our remaining operated Oklahoma production assets for cash consideration of $5.5 million, subject to customary post-closing adjustments, and assumption by the buyer of certain plugging and abandonment costs. In August 2017, we completed construction of the “SECO Pipeline,” a natural gas pipeline with 400 MMcf/d of capacity that is designed and used to transport dry gas from the Raptor Gas Processing Facility (defined below) to multiple markets in South Texas. On October 12, 2017, we signed a purchase and sale agreement to sell certain oil and natural gas properties in Texas.

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These unaudited condensed consolidated financial statements include the accounts of SNMP and our wholly owned subsidiaries.  All intercompany accounts and transactions have been eliminated in consolidation.  We conduct our business activities as two operating segments: the production of oil and natural gas and the midstream business, which includes Western Catarina Midstream (defined below).  Our management evaluates performance based on these two business segments.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (“SEC”).  Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”), have been condensed or omitted pursuant to those rules and regulations.  We believe that the disclosures made are adequate to make the information presented not misleading.  In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included.  The results of operations for the interim periods are not necessarily indicative of the results for the entire year. 

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These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of SNMP and its subsidiaries included 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. 

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued  standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption.

In August 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which changes the recognition and presentation requirements of hedge accounting, including eliminating the requirement to separately measure and report hedge ineffectiveness, and presenting all items that affect earnings in the same income statement line item as the hedged item.  The ASU also provides new alternatives for applying hedge accounting.  This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018.  Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements.

In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods 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 December 2016, the FASB issued ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are effective upon issuance (December 2016).

In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is effective for public business entities for annual and interim periods 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 will be effective beginning with the first quarter 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 March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. The adoption of this guidance did not have a material impact on our consolidated financial statements.

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

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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 not early adopt the standard although early adoption is permitted. The Partnership’s expectation is to apply the modified retrospective approach. As part of the assessment, the Partnership has formed an implementation work team, completed trainings on the new revenue recognition model and gathered a representative sample of material revenue contracts covering current revenue streams for which we are currently evaluating the impact under the new standard. The Company is currently collecting all remaining contracts and evaluating the impacts to its consolidated financial statements under the revised standards. In addition, the Company is evaluating the impacts of significant historical transactions under the new standard.

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates. 

3. ACQUISITIONS AND DIVESTITURES

Our acquisitions are accounted for under the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.” A business combination may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties obtained through our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions.

Texas Production Divestiture

On October 12, 2017, the Partnership entered into a purchase and sale agreement with Dallas Petroleum Group, LLC pursuant to which the Partnership has agreed to sell to Dallas Petroleum Group, LLC, on the closing date, specified oil and gas wells, leases and other associated assets and interests located in Texas (the “Texas Production Assets”) for cash consideration of approximately $6.3 million, subject to adjustment for title and environmental defects (the “Texas Production Divestiture”).  In addition, the buyer has agreed to assume all obligations relating to the assets, including all plugging and abandonment costs relating to the assets, that arose on or after October 1, 2017.  The Texas Production Divestiture is anticipated to close during the fourth quarter 2017. We anticipate reporting a gain on the sale during the fourth quarter 2017.  On October 12, 2017, a purchase and sale agreement entered into by a wholly owned subsidiary of the Partnership and Sendero Petroleum, LLC, dated June 30, 2017, relating to the sale of the Texas Production Assets, was terminated by the Partnership as a result of the closing not having occurred by the outside date specified therein.

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Non-Operated Production Divestiture

On July 14, 2017, we entered into an agreement to assign certain non-operated production assets located in Oklahoma, as well as our equity interests in the entities that owned the assets, in exchange for agreeing upon the apportionment of certain shared litigation costs (the “Non-Operated Production Divestiture”). The assignment was effective as of July 14, 2017.

Oklahoma Production Divestiture

On May 10, 2017, we entered into a purchase and sale agreement to sell all of the Partnership’s equity interests in the entities that owned our remaining Oklahoma production assets for cash consideration of $5.5 million, subject to adjustment for title and environmental defects (the “Oklahoma Production Divestiture”), and assumption by the buyer of all obligations relating to the assets arising after the closing date and all plugging and abandonment costs relating to the assets arising prior to the closing date. The transaction closed July 17, 2017. We recorded a gain of $2.4 million on the sale during the third quarter 2017.

Carnero Processing Acquisition

On November 22, 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Processing from SN Midstream, LLC, a wholly owned subsidiary of Sanchez Energy (“SN Midstream”), for cash consideration of approximately $55.5 million and the assumption of approximately $24.5 million of remaining capital commitments to Carnero Processing (the “Carnero Processing Transaction”). The remaining 50% membership interests in Carnero Processing are owned by TPL SouthTex Processing Company LP, an affiliate of Targa Resources Group (“Targa”). Carnero Processing owns a cryogenic gas processing facility located in La Salle County, Texas that is operated by Targa (the “Raptor Gas Processing Facility”). See Note 10. “Investments” for additional information relating to the Carnero Processing Transaction.

The Partnership made capital contributions to Carnero Processing totaling $15.8 million between November 22, 2016 and September 30, 2017.

Production Acquisition

On November 22, 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 for aggregate cash consideration of approximately $24.2 million after approximately $2.8 million in normal and customary closing adjustments (the “Production Acquisition”). The effective date of the transaction was July 1, 2016. The Production Acquisition included initial conveyed working interests and net revenue interests which, for certain properties, escalated on January 1, 2017 and will escalate again on January 1, 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

On July 5, 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Gathering from SN Midstream for cash consideration of approximately $37.0 million, and the assumption of approximately $7.4 million of remaining capital commitments to Carnero Gathering (the “Carnero Gathering Transaction”).  In addition, the Partnership is required to pay SN Midstream a monthly earnout based on gas received from SN Catarina, LLC, a wholly owned subsidiary of Sanchez Energy (“SN Catarina”), at Carnero Gathering’s receipt points, as well as gas delivered and processed at the Raptor Gas Processing Facility for other producers. The remaining 50% membership interests in Carnero Gathering are owned by Targa. Carnero Gathering owns a gas gathering pipeline in the Western Eagle Ford in South Texas that is operated by Targa and interconnects with the Raptor Gas Processing Facility. See Note 10. “Investments” for additional information relating to the Carnero Gathering Transaction.

The Partnership made capital contributions to Carnero Gathering totaling $8.4 million between July 5, 2016 and September 30, 2017.

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Mid-Continent Divestiture

On June 15, 2016, certain wholly owned subsidiaries of the Partnership entered into an agreement with Gateway Resources U.S.A., Inc. (“Gateway”) to sell substantially all of the Partnership’s operated production assets 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, subject to adjustment for title and environmental defects, effective as of August 1, 2016. In addition, Gateway agreed to assume all obligations relating to the assets arising after the effective date and all plugging and abandonment costs relating to the assets arising prior to the effective date. The Partnership closed the sale of this transaction on July 15, 2016. The Partnership recorded a $0.2 million loss related to an intangible asset balance comprised of marketing contracts from the 2007 Newfield 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 September 30, 2017 (in thousands):

	Fair Value Measurements at September 30, 2017
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
Derivative assets (net)	$	—	$	5,263	$	—	$	5,263
Total net assets	$	—	$	5,263	$	—	$	5,263

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
Derivative assets (net)	$	—	$	6,436	$	—	$	6,436
Total net assets	$	—	$	6,436	$	—	$	6,436

As of September 30, 2017, and December 31, 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.

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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 8, “Asset Retirement Obligation.”

The following table summarizes the non-recurring fair value measurements of our assets as of September 30, 2017 (in thousands):

	Fair Value Measurements at September 30, 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 nine months ended September 30, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas properties 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 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) During 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 fair values of oil and natural gas properties were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) 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.

Fair Value of Financial Instruments

Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports.  The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

Credit Agreement – We believe that the carrying value of long-term debt for our Credit Agreement (defined below) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms.  The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties.  Our Credit Agreement is discussed further in Note 6, “Long-Term Debt.”

Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs.  Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate.  Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate derivatives as of September 30, 2017. We prioritize the use of the highest level inputs available in determining fair value such that fair

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value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.

Embedded Derivative – 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. We therefore classified the fair value measurements of our embedded derivative as Level 3 inputs. 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 fixed and the provisions that required the bifurcation were removed.  At that time, the fair value of the derivative was transferred to mezzanine equity.

The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded derivative classified as Level 3 in the fair value hierarchy for the year ended December 31, 2016 (in thousands):

	December 31,
	2016
Beginning balance	$	(193,077)
Gain on embedded derivative		47,794
Transfer to mezzanine equity		145,283
Ending balance	$	—
Loss included in earnings related to derivatives still held as of December 31, 2016	$	—

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 condensed 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 in natural gas sales and oil sales in the condensed consolidated statements of operations.

As of September 30, 2017, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:

Fixed Price Basis Swaps–West Texas Intermediate (WTI)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price
2017	—	$	—	—	$	—	—	$	—	64,568	$	59.83	64,568	$	59.83
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
													758,656

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Fixed Price Swaps—NYMEX (Henry Hub)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price
2017	—	$	—	—	$	—	—	$	—	124,160	$	3.79	124,160	$	3.79
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
													1,480,136

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the nine months ended September 30, 2017 and the year ended December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Beginning fair value of commodity derivatives	$	6,436	$	31,018
Net gains (losses) on crude oil derivatives		7,087		(8,355)
Net gains (losses) on natural gas derivatives		497		1,116
Net settlements on derivative contracts:
Crude oil		(6,133)		(13,622)
Natural gas		(2,624)		(6,919)
Net premiums on derivative contracts		—		3,198
Ending fair value of commodity derivatives	$	5,263	$	6,436

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

		Amount of Gain (Loss) in Income
	Location of Gain (Loss)	Three Months Ended September 30,				Nine Months Ended September 30,
Derivative Type	in Income	2017		2016		2017		2016
Commodity – Oil Hedges	Oil sales	$	(1,456)	$	(1,032)	$	7,087	$	(4,600)
Commodity – Gas Hedges	Natural gas sales		(228)		2,104		497		1,936
		$	(1,684)	$	1,072	$	7,584	$	(2,664)

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 crude 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 September 30, 2017, and December 31, 2016, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant.

Embedded Derivative

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.

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The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the year ended December 31, 2016 (in thousands):

	December 31,
	2016
Beginning fair value of embedded derivative	$	(193,077)
Gain on embedded derivative		47,794
Transfer to mezzanine equity		145,283
Ending fair value of embedded derivative	$	—

6. LONG-TERM DEBT

We have entered into a credit facility 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 properties.  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 multiplied by 4.5.  Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral.  We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months.  Any increase in our borrowing base must be approved by all of the lenders.  As of September 30, 2017, the borrowing base under the Credit Agreement was $215.6 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.

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.  

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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 September 30, 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 for any violation of a financial covenant from the lenders, but there is no assurance that such waivers would be granted.

Debt Issuance Costs

As of September 30, 2017, and December 31, 2016, our unamortized debt issuance costs were $1.3 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 three months ended September 30, 2017 and 2016 were $0.1 million. Amortization of debt issuance costs recorded during the nine months ended September 30, 2017 and 2016 were $0.4 million.

7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT

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

	September 30,		December 31,
	2017		2016
Gathering and transportation assets
Midstream assets	$	183,681	$	152,209
Less: Accumulated depreciation and amortization		(24,983)		(15,020)
Total gathering and transportation assets	$	158,698	$	137,189

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

	September 30,		December 31,
	2017		2016
Oil and natural gas properties and related equipment
Property costs
Proved property	$	200,422	$	758,366
Unproved property		49		46
Land		—		501
Total property costs		200,471		758,913
Materials and supplies		—		1,056
Total		200,471		759,969
Less: Accumulated depreciation, depletion, amortization and impairments		(137,420)		(674,338)
Oil and natural gas properties and equipment, net	$	63,051	$	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.

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.

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.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Depreciation, depletion and amortization of oil and natural gas-related assets	$	1,739	$	2,348	$	7,850	$	5,310
Depreciation, depletion and amortization of gathering and transportation-related assets		1,780		1,731		9,963		5,169
Amortization of intangible assets		3,380		3,428		10,204		10,345
Total depreciation, depletion and amortization		6,899		7,507		28,017		20,824
Asset impairments		—		—		4,688		1,309
Total	$	6,899	$	7,507	$	32,705	$	22,133

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 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.

For the three months ended September 30, 2017, we recorded no impairment charges. For the nine months ended September 30, 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 three months ended September 30, 2016, we did not record impairment charges. For the nine months ended September 30, 2016, we recorded non-cash charges of $1.3 million, to impair our producing oil and natural gas properties in Texas and Louisiana acquired prior to the Eagle Ford acquisition.

Asset Retirement Obligation.  As described in Note 8, 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 nine months ended September 30, 2017 or 2016.

8. 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 or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method 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.

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

	September 30,		December 31,
	2017		2016
Asset retirement obligation, beginning balance	$	13,579	$	20,364
Liabilities added from acquisitions		198		912
Sold		(6,582)		(6,291)
Revisions to cost estimates		—		(2,399)
Settlements		(46)		(134)
Accretion expense		647		1,127
Asset retirement obligation, ending balance	$	7,796	$	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 and other facilities reduce the liability for AROs. During the nine months ended September 30, 2017, and the year ended December 31, 2016, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the nine months ended September 30, 2017, obligations were sold as part of the Oklahoma 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. Additional reductions in future abandonment obligations are expected in the fourth quarter 2017 as a result of the expected Texas Production Divestiture.

9. INTANGIBLE ASSETS

Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $175.5 million related to the gathering agreement with Sanchez Energy that was entered into as part of the acquisition of the Western Catarina gathering system (“Western Catarina Midstream”). Pursuant to the 15-year agreement, Sanchez Energy tenders all of its crude 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. During 2016, the intangible asset balance was reduced by $0.2 million due to marketing contracts from the 2007 Newfield acquisition which were included in the Mid-Continent Divestiture.

Amortization expense for the nine months ended September 30, 2017 and 2016 was $10.2 million and $10.3 million, respectively.  These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations.  Intangible assets as of September 30, 2017, and December 31, 2016 are detailed below (in thousands):

	September 30,		December 31,
	2017		2016
Beginning balance	$	185,766	$	199,741
Disposals		(32)		(219)
Amortization		(10,204)		(13,756)
Ending balance	$	175,530	$	185,766

10. INVESTMENTS

On July 5, 2016, the Partnership purchased a 50% membership interest in Carnero Gathering from SN Midstream 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 remaining 50% membership interests of Carnero Gathering are owned by an affiliate of Targa. During the nine months ended September 30, 2017, the Partnership made approximately $5.1 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $26.0 million in the Carnero Gathering joint venture. 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 the contract term of fifteen years and decrease earnings from Carnero Gathering. As part of the Carnero Gathering Transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered by other producers and processing by Carnero Processing. This earnout is considered as contingent consideration and its estimated fair value of $4.0 million was recorded on the balance sheet as a deferred liability as of September 30, 2017.  No earnout payments were made in the three or nine months ended September 30, 2017.

As of September 30, 2017, the Partnership had paid approximately $45.9 million for the Carnero Gathering Transaction related to the initial purchase price, acquisition costs and contributed capital to date. The Partnership has accounted for this investment as an equity

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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 Condensed Consolidated Balance Sheet. For the nine months ended September 30, 2017, the Partnership recorded earnings of approximately $4.7 million in equity investments from Carnero Gathering, which was offset by approximately $0.6 million related to the amortization of the contractual customer intangible asset. For the three months ended September 30, 2017, the Partnership recorded earnings of approximately $2.0 million in equity investments from Carnero Gathering, which was offset by approximately $0.2 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 Condensed Consolidated Statements of Operations. Cash distributions of $5.3 million were received during the nine months ended September 30, 2017.

On November 22, 2016, the Partnership purchased a 50% membership interest in Carnero Processing from SN Midstream 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 remaining 50% membership interests of Carnero Processing are owned by an affiliate of Targa. During the nine months ended September 30, 2017, the Partnership made $5.3 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $48.0 million in the Carnero Processing joint venture.

As of September 30, 2017, the Partnership had paid approximately $71.8 million for the Carnero Processing transaction related to the initial payment, acquisition costs 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 expenses of approximately $0.5 million in the “Earnings from equity investments” line within our consolidated statements of operations for the nine months ended September 30, 2017 and $1.0 million for the three months ended September 30, 2017.

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

	Nine Months Ended
	September 30,
	2017
Sales	$	57,406
Total expenses		46,734
Net income	$	10,672

	September 30,		December 31,
	2017		2016
Current assets	$	28,318	$	27,779
Noncurrent assets		190,100		152,112
Current liabilities		18,040		16,577

11. COMMITMENTS AND CONTINGENCIES

As part of the Carnero Gathering Transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered and processed at Carnero Processing by other producers which began at the end of the second quarter 2017. This earnout has an approximate value of $4.0 million and was recorded on the balance sheet as a deferred liability as of September 30, 2017. We did not have any other material commitments and contingencies and no payments were made as of September 30, 2017.

12. RELATED PARTY TRANSACTIONS

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, professionals, 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 additional one-year terms unless either Manager or the

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Partnership provides notice of termination to the other with at least 180 days’ notice.  During the nine months ended September 30, 2017, we expensed approximately $6.5 million to Manager pursuant to the Services Agreement.

Manager utilizes Sanchez Oil & Gas Corporation (“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, the President and Chief Operating Officer of our general partner, Eduardo A. Sanchez, one of our directors, 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.

In October 2015, the Partnership entered into a Firm Gathering and Processing Agreement with Sanchez Energy for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas is dedicated for gathering by Catarina Midstream, LLC (the “Gathering Agreement”). In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. 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 of September 30, 2017, and December 31, 2016, the Partnership had a net receivable from related parties of $6.7 million and $6.0 million, respectively, which are included in “Accounts receivable – related entities” in the condensed consolidated balance sheets. As of September 30, 2017, and December 31, 2016, the Partnership also had a net payable to related parties of $6.5 million and $7.0 million, respectively. The net receivables/payable as of September 30, 2017, and 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, development of gathering and transportation assets and obligations for general and administrative costs. 

In July 2016, we acquired 50% of the outstanding membership interests in Carnero Gathering from SN Midstream for cash consideration of approximately $37.0 million, and the assumption of approximately $7.4 million of remaining capital commitments to Carnero Gathering.  In addition, the Partnership is required to pay SN Midstream a monthly earnout based on gas received from SN Catarina at Carnero Gathering’s receipt points, as well as gas delivered and processed at the Raptor Gas Processing Facility for other producers. The remaining 50% of the membership interests are owned by an affiliate of Targa. Carnero Gathering operates a gas gathering pipeline in the Western Eagle Ford in South Texas that interconnects with the Raptor Gas Processing Facility. The Partnership made capital contributions to Carnero Gathering totaling $8.4 million between July 5, 2016, and September 30, 2017. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.”

In October 2016, the Partnership entered into a Purchase and Sale Agreement (the “Lease Option Purchase Agreement”) with Sanchez Energy and SN Terminal, LLC (“SNT”), pursuant to which SNT granted and conveyed to the Partnership an option to acquire a ground lease (the “Lease Option”) to which SNT is a party for a tract of land leased from the Calhoun Port Authority in Point Comfort, Texas. The Partnership, Sanchez Energy and SNT entered into an agreement terminating the Lease Option on September 11, 2017.

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 (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. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.”

In November 2016, we acquired 50% of the outstanding membership interests in Carnero Processing from SN Midstream for cash consideration of approximately $55.5 million and the assumption of approximately $24.5 million of remaining capital commitments to Carnero Processing.  The Partnership made capital contributions to Carnero Processing totaling $15.8 million between November 22, 2016 and September 30, 2017.  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 interest in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas as well as escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas for approximately $24.2 million. See further discussion of the transactions in Note 3, “Acquisitions and Divestitures.”

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On September 1, 2017, we entered into an agreement with SN Catarina to transport certain quantities of SN Catarins’s natural gas on a firm basis through the SECO Pipeline for $0.22 per MMBtu delivered on or after September 1, 2017. This agreement has an initial term of one month that expired on September 30, 2017, but continues month to month thereafter unless terminated by either party.

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 Eagle Ford Shale in South Texas where it has assembled approximately 356,000 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 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, Patricio D. Sanchez and Eduardo A. Sanchez beneficially own approximately 7.4%, 3.2%, 1.1% and 1.7%, respectively, of Sanchez Energy’s shares outstanding as of September 30, 2017. Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owns approximately 15.4% of the outstanding common units of SNMP.

13. UNIT-BASED COMPENSATION

The Sanchez Midstream Partners LP Long-Term Incentive Plan (the “LTIP”) allows for restricted common unit grants. Restricted common unit activity under the LTIP 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, 2016	219,144	$	14.22
Granted	215,814		14.83
Vested	(46,583)		15.61
Returned/Cancelled	(3,333)		13.59
Outstanding at September 30, 2017	385,042	$	14.40

In March 2017, the Partnership issued 171,231 restricted common units pursuant to the LTIP 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 LTIP 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 LTIP 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 September 30, 2017, 1,575,643 common units remain available for future issuance to participants under the LTIP.

14. DISTRIBUTIONS TO UNITHOLDERS

The table below reflects the payment of cash distributions on common units related to the nine months ended September 30, 2017, and the previous distributions.

	Distribution		Date of	Date of	Date of
Three Months Ended	Per Unit		Declaration	Record	Distribution
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

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The table below reflects the payment of distributions on Class B preferred units related to the nine months ended September 30, 2017, and the previous distributions.

	Distribution		Date of	Date of	Date of
Three Months Ended	Per Unit		Declaration	Record	Distribution
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 (b)	$	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

(a) The Partnership elected to pay the fourth quarter 2016 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.

(b) The Partnership elected to pay the 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 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017.

15. PARTNERS’ CAPITAL

Outstanding Units 

As of September 30, 2017, we had 31,000,887 Class B Preferred Units outstanding, and 14,773,192 common units outstanding.

Common Unit Issuances

In connection with providing services under the Services Agreement for the first and second quarters of 2017, the Partnership issued 139,110 and 170,497 common units, respectively, to SP Holdings, LLC on June 30, 2017 and August 31, 2017, respectively. In connection with providing services under the Services Agreement for the third and fourth quarters of 2016, the Partnership issued 170,750 and 154,737 common units, respectively, to SP Holdings, LLC on March 6, 2017. See Note 12, “Related Party Transactions” for additional information related to the Services Agreement.

The Partnership elected to pay the 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 issued 184,697 common units on May 22, 2017, to the holder of Class B preferred units.

In April 2017, we issued 84,577 common units in registered offerings for gross proceeds of approximately $1.3 million pursuant to a shelf registration statement originally filed with the SEC on March 6, 2015 as updated by that certain prospectus supplement filed with the SEC on April 6, 2017 (the “Shelf Registration Statement”). The Shelf Registration Statement allows the Partnership to sell up to $50.0 million of common units at-the-market to fund general limited partnership purposes, including possible acquisitions. Proceeds from the at-the-market equity issuance were used for general limited partnership purposes.

The Partnership elected to pay the fourth quarter 2016 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 issued 208,594 common units on February 20, 2017 to the holder of Class B preferred units.

In November 2016, we completed a public offering and private placement of common units. The public offering consisted of 6,745,107 common units (which includes partial exercise of the underwriters’ overallotment of 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses. The private placement consisted of 2,272,727 common units issued to Sanchez Energy for net proceeds of approximately $25.0 million.

In March 2016, the Partnership converted all remaining outstanding Class A Preferred Units into common units of the Partnership on a one for one basis, adjusted for the 1-for-10 unit split in August 2015.

Class B Preferred Unit Offering

On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a privately negotiated transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of approximately $350.0

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million. The Partnership used the net proceeds to pay a portion of the consideration for the acquisition of Western Catarina Midstream, along with the payment to Stonepeak of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units. 

Under the terms of our partnership agreement, holders of the Class B Preferred Units received 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):

	September 30,		December 31,
	2017		2016
Mezzanine equity beginning balance	$	342,991	$	172,111
Discount		—		(87)
Amortization of discount		1,300		23,477
Distributions		27,125		39,375
Distributions paid		(28,000)		(37,168)
Transfer embedded derivative to Class B		—		145,283
Total mezzanine equity	$	343,416	$	342,991

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) based on provisions of the partnership agreement, 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) as if all of the net income for the period had been distributed in accordance with the partnership agreement. 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 based on provisions of the partnership agreement. 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.

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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:  

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Weighted Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675
Weighted Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675

At September 30, 2017, we had 385,042 common units that were restricted unvested common units granted and outstanding.  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 three months ended September 30, 2017 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(5,442)	$	(5,442)
Basic and diluted loss per unit			$	(0.38)

The following table presents our basic and diluted loss per unit for the three months ended September 30, 2016 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed income to be allocated	$	9,949	$	9,949
Basic earnings per unit			$	2.49
Assumed income to be allocated	$	28,807	$	28,807
Diluted earnings per unit			$	1.21

The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2017 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(31,754)	$	(31,754)
Basic and diluted loss per unit			$	(2.29)

The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2016 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(17,997)	$	(17,997)
Basic and diluted loss per unit			$	(5.06)

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16. REPORTING SEGMENTS

“Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting 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 crude oil, natural gas and NGLs. 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 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.

The following tables set forth our segment information for the periods indicated (in thousands):

	Three Months Ended September 30, 2017
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	787	$	—	$	787
Oil sales		3,061		—		3,061
Natural gas liquids sales		514		—		514
Gathering and transportation sales		—		14,234		14,234
Total operating revenues		4,362		14,234		18,596
Operating expenses:
Lease operating expenses		1,585		150		1,735
Transportation operating expenses		—		2,661		2,661
Production taxes		340		—		340
General and administrative		4,199		1,415		5,614
Unit-based compensation expense		631		—		631
Gain on sale of assets		(2,546)		—		(2,546)
Depreciation, depletion and amortization		1,756		5,143		6,899
Accretion expense		80		69		149
Total operating expenses		6,045		9,438		15,483
Operating income (loss)	$	(1,683)	$	4,796	$	3,113

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	Three Months Ended September 30, 2016
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	4,434	$	—	$	4,434
Oil sales		2,159		—		2,159
Natural gas liquids sales		264		—		264
Gathering and transportation sales		—		12,997		12,997
Total operating revenues		6,857		12,997		19,854
Operating expenses:
Lease operating expenses		2,650		117		2,767
Transportation operating expenses		—		3,111		3,111
Cost of sales		99		—		99
Production taxes		290		—		290
General and administrative		4,778		1,508		6,286
Unit-based compensation expense		90		—		90
Loss on sale of assets		219		—		219
Depreciation, depletion and amortization		2,411		5,096		7,507
Accretion expense		207		64		271
Total operating expenses		10,744		9,896		20,640
Operating income (loss)	$	(3,887)	$	3,101	$	(786)

	Nine Months Ended September 30, 2017
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	5,818	$	—	$	5,818
Oil sales		22,520		—		22,520
Natural gas liquids sales		1,473		—		1,473
Gathering and transportation sales		—		39,621		39,621
Total operating revenues		29,811		39,621		69,432
Operating expenses:
Lease operating expenses		9,957		642		10,599
Transportation operating expenses		—		8,989		8,989
Cost of sales		77		—		77
Production taxes		1,166		—		1,166
General and administrative		13,195		4,381		17,576
Unit compensation expense		1,951		—		1,951
Gain on sale of assets		(2,546)		—		(2,546)
Depreciation, depletion and amortization		7,961		20,056		28,017
Asset impairments		4,688		—		4,688
Accretion expense		444		203		647
Total operating expenses		36,893		34,271		71,164
Operating income (loss)	$	(7,082)	$	5,350	$	(1,732)

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	Nine Months Ended September 30, 2016
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	8,709	$	—	$	8,709
Oil sales		4,746		—		4,746
Natural gas liquids sales		784		—		784
Gathering and transportation sales		—		41,130		41,130
Total operating revenues		14,239		41,130		55,369
Operating expenses:
Lease operating expenses		11,430		488		11,918
Transportation operating expenses		—		9,179		9,179
Cost of sales		292		—		292
Production taxes		837		—		837
General and administrative		12,762		4,221		16,983
Unit-based compensation expense		1,619		—		1,619
Loss on sale of assets		219		—		219
Depreciation, depletion and amortization		5,560		15,264		20,824
Asset impairments		1,309		—		1,309
Accretion expense		714		187		901
Total operating expenses		34,742		29,339		64,081
Operating income (loss)	$	(20,503)	$	11,791	$	(8,712)

The following table summarizes the total assets by operating segment as of September 30, 2017 and December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Segment Assets
Production	$	189,374	$	207,219
Midstream		344,310		332,486
Total assets	$	533,684	$	539,705

17. VARIABLE INTEREST ENTITIES

As noted above in Note 10, “Investments,” the Partnership acquired a 50% membership interest in Carnero Gathering from SN Midstream 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 variable interest entity (“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 $48.1 million.

As of September 30, 2017, the Partnership had invested approximately $45.9 million in Carnero Gathering. As of September 30, 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 10, “Investments,” the Partnership acquired a 50% membership interest in Carnero Processing from SN Midstream 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

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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 $80.4 million.

As of September 30, 2017, the Partnership had invested approximately $71.8 million in Carnero Processing. As of September 30, 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 September 30, 2017 and December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Capital investments	$	117,699	$	107,320
Earnings in equity investments		6,800		2,301
Distributions received		(8,245)		(2,950)
Estimated earnout accrued		4,049		4,270
Equity in equity investments	$	120,303	$	110,941
	September 30,		December 31,
	2017		2016
Equity in equity investments	$	120,303	$	110,941
Guarantees of capital investments		8,247		17,584
Maximum exposure to loss	$	128,550	$	128,525

18. SUBSEQUENT EVENTS

On November 7, 2017, the board of directors of our general partner declared a third quarter 2017 cash distribution on the Partnership’s common units of $0.4508 per unit ($1.8032 per unit annualized) payable on November 30, 2017 to holders of record on November 20, 2017. The Partnership also declared a third 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 payable on November 30, 2017 to holders of record on November 20, 2017.

On November 13, 2017, we closed the Texas Production Divestiture pursuant to which we sold certain non-operated production assets located in Texas for cash consideration of approximately $6.3 million. In addition, the buyer assumed all obligations relating to the assets arising after the effective time.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 

The following discussion and analysis should be read in conjunction with the financial statements and the summary of significant accounting policies and notes included herein and in our most recent Annual Report on Form 10-K. The following discussion contains “Forward-Looking Statements” that reflect our future plans, estimates, forecasts, guidance, beliefs and expected performance. Please read “Cautionary Note Regarding Forward-Looking Statements.”

Overview

Sanchez Midstream Partners LP, a Delaware limited partnership, (together with our consolidated subsidiaries, “SNMP,” “we,” “us,” “our” or the “Partnership”) (formerly Sanchez Production Partners LP), is a growth oriented publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and production assets in North America. We have entered into a shared services agreement (the “Services Agreement”) with SP Holdings, LLC (the “Manager”), the sole member of our general partner, pursuant to which the Manager provides services that the Partnership requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. Our common units are currently listed on the NYSE American under the symbol “SNMP,” and were traded under the symbol “SPP” prior to our recent name change.

Historically, our operations have consisted of the production of proved reserves located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana.  In October 2015, we consummated the acquisition of midstream assets in the Eagle Ford Shale from Sanchez Energy Corporation (“Sanchez Energy”) and entered into a 15-year gathering and processing agreement with Sanchez Energy.  We also commenced a process to sell our production assets in the Mid-Continent region. In July 2016, we sold a portion of our production assets in the Mid-Continent region and acquired a 50% equity interest in Carnero Gathering. In November 2016, we completed a public offering of approximately 6,745,107 common units (which includes exercise of the underwriters’ option to purchase 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses.  Concurrent with the public offering, we completed a private placement of 2,272,727 common units representing limited partner interests for net proceeds of approximately $25.0 million.  The combined proceeds were used to close the acquisition of a 50% equity interest in Carnero Processing, and the acquisition of working interest in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas and escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas. In July 2017, we sold our equity interests in the entities that owned our remaining operated Oklahoma production assets for cash consideration of $5.5 million, subject to customary post-closing adjustments, and assumption by the buyer of certain plugging and abandonment costs. In August 2017, we completed construction of the SECO Pipeline, a natural gas pipeline with 400 MMcf/d capacity that is designed and used to transport dry gas from the Raptor Gas Processing Facility to multiple markets in South Texas. On October 12, 2017, we signed a purchase and sale agreement to sell certain oil and natural gas properties in Texas (the “Texas Production Divestiture”).

How We Evaluate our Operations

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

· our throughput volumes on gathering and transportation systems;

· our operating expenses; and

· our Adjusted EBITDA, a non-GAAP financial measure (for a reconciliation of Adjusted EBITDA to the most comparable GAAP financial measure 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 the Western Catarina Midstream. Our success in connecting additional wells is impacted by successful drilling activity by Sanchez Energy on the acreage dedicated to the 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. Gas is currently being transported through the SECO Pipeline under a month-

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to-month agreement. Future throughput volumes on the pipeline are dependent on the continuation of the month-to-month agreement or execution of a new agreement.

Operating Expenses

Our management seeks to maximize Adjusted EBITDA, a non-GAAP financial measure, 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 quarterly report. We believe that non-GAAP financial measures are helpful in understanding our past financial performance and potential future results, particularly in light of the effect of various transactions effected by us. We define Adjusted EBITDA as net income (loss) adjusted by: (i) interest (income) expense, net, which includes interest expense, interest expense net (gain) loss on interest rate derivative contracts, and interest (income); (ii) income tax expense (benefit); (iii) depreciation, depletion and amortization; (iv) asset impairments; (v) accretion expense; (vi) (gain) loss on sale of assets; (vii) unit-based compensation programs; (viii) unit-based asset management fees; (ix) distributions in excess of equity earnings; (x) (gain) loss on mark-to-market activities; (xi) commodity derivatives settlements applied to future positions; (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 flow at a level that can sustain or support a quarterly distribution or any increase in our quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts, our lenders and others to assess: (i) the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; (ii) the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and (iii) our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital structure.

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

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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 Three Months Ended				For the Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Net income (loss)	$	3,771	$	28,807	$	(3,329)	$	32,132
Adjusted by:
Interest expense, net		2,215		1,543		5,994		3,545
Depreciation, depletion and amortization		6,899		7,507		28,017		20,824
Asset impairments		—		—		4,688		1,309
Accretion expense		149		271		647		901
(Gain) loss on sale of assets		(2,546)		219		(2,546)		219
Unit-based compensation expense		631		90		2,648		1,619
Unit-based asset management fees		2,103		1,991		6,478		4,903
Distributions in excess of equity earnings		517		1,094		2,288		1,094
Loss on mark-to-market activities		7,000		6,538		1,173		22,852
Commodity derivatives settled early		(3,602)		(3,197)		(3,602)		(3,197)
Gain on embedded derivatives		—		(30,012)		—		(43,204)
Acquisition and divestiture costs		614		—		1,167		—
Adjusted EBITDA	$	17,751	$	14,851	$	43,623	$	42,997

Significant Operational Factors

· Throughput. During the three months ended September 30, 2017, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 10.7 MBbls/d of crude oil, 162.5 MMcf/d of natural gas and 16.6 MBbls/d of water. During the three months ended September 30, 2016, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 12.1 MBbls/d of crude oil, 175.6 MMcf/d of natural gas and an insignificant amount of water. During the nine months ended September 30, 2017, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 11.2 MBbls/d of crude oil, 161.3 MMcf/d of natural gas and 11.2 MBbls/d of water. During the nine months ended September 30, 2016, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 13.4 MBbls/d of crude oil, 185.5 MMcf/d of natural gas and an insignificant amount of water.There was an insignificant amount of natural gas that was transported through the SECO pipeline during the three months ended September 30, 2017.

· Production. Our production for the three months ended September 30, 2017, was 188 MBOE, or an average of 2,043 BOE per day, compared with approximately 264 MBOE, or an average of 2,870 BOE per day, for the three months ended September 30, 2016.  Our production for the nine months ended September 30, 2017, was 788 MBOE, or an average of 2,886 BOE per day, compared with approximately 871 MBOE, or an average of 3,179 BOE per day, for the nine months ended September 30, 2016.

· Capital Expenditures. For the three months ended September 30, 2017, we spent approximately $7.5 million in capital expenditures, consisting of $7.3 million related to the development of the SECO Pipeline and $0.2 million related to the development of Western Catarina Midstream. For the three months ended September 30, 2016, we spent approximately $0.3 million in capital expenditures, related to the development of Western Catarina Midstream. For the nine months ended September 30, 2017, we spent approximately $31.5 million in capital expenditures, consisting of $29.0 million related to the development of the SECO Pipeline and $2.5 million related to the development of Western Catarina Midstream. For the nine months ended September 30, 2016, we spent approximately $2.7 million in capital expenditures, consisting of $2.1 million related to the development of Western Catarina Midstream, and $0.6 million related to the development of oil and natural gas properties in the Palmetto Field in Gonzales County.  These expenditures were funded with cash on hand and borrowings under our Credit Agreement.

· Hedging Activities. For the three months ended September 30, 2017, the non-cash mark-to-market loss for our commodity derivatives was approximately $7.0 million, compared to a loss of $6.5 million for the same period in 2016.  For the nine months ended September 30, 2017, the non-cash mark-to-market loss for our commodity derivatives was approximately $1.2 million, compared to a loss of $22.9 million for the same period in 2016.

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Recent Developments

On November 7, 2017, the board of directors of our general partner declared a third quarter 2017 cash distribution on the Partnership’s common units of $0.4508 per unit ($1.8032 per unit annualized) payable on November 30, 2017 to holders of record on November 20, 2017.  The Partnership also declared a third 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 payable on November 30, 2017 to holders of record on November 20, 2017.

On November 13, 2017, we closed the Texas Production Divestiture pursuant to which we sold certain non-operated production assets in Texas for cash consideration of approximately $6.3 million. In addition, the buyer assumed all obligations relating to the assets arising after the October 1, 2017 effective time.

Results of Operations by Segment

Three months ended September 30, 2017 compared to three months ended September 30, 2016 

Midstream Operating Results

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

	For the Three Months Ended
	September 30,
	2017		2016			Variance
Revenues:
Gathering and transportation sales	$	14,234	$	12,997	$	1,237	10	%
Total gathering and transportation sales		14,234		12,997		1,237	10	%
Operating expenses:
Lease operating expenses		150		117		33	28	%
Transportation operating expenses		2,661		3,111		(450)	(14)	%
General and administrative		1,415		1,508		(93)	(6)	%
Depreciation and amortization expense		5,143		5,096		47	1	%
Accretion expense		69		64		5	8	%
Total operating expenses		9,438		9,896		(458)	(5)	%
Operating income	$	4,796	$	3,101	$	1,695	55	%

Gathering and transportation sales.  We consummated the acquisition of Western Catarina Midstream from Sanchez Energy and entered into the related gathering and processing agreement with Sanchez Energy in October 2015. On June 30, 2017, the gathering and processing agreement with Sanchez Energy was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018. During the three months ended September 30, 2017, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 10.7 MBbls/d of crude oil, 162.5 MMcf/d of natural gas and 16.6 MBbls/d of water. During the three months ended September 30, 2016, Sanchez Energy transported average daily production through Western Catarina Midstream of approximately 12.1 MBbls/d of crude oil, 175.6 MMcf/d of natural gas and an insignificant amount of water. The decrease in throughput was driven by a decrease in Sanchez Energy’s Catarina production by 262 MBoe over the three months ended September 30, 2017 compared to the same period in 2016.

Lease operating expense.Lease operating expenses, which includes ad valorem taxes, remained flat for the three months ended  September 30, 2017 and 2016.

Transportation operating expenses.   Our operating expenses generally consist of equipment rentals, chemicals, treating, metering fees, permit and regulatory fees, labor, minor maintenance, tools, supplies, and integrity management expenses. Our transportation operating expenses decreased $0.4 million, to $2.7 million for the three months ended September 30, 2017, compared to $3.1 million during the same period in 2016 which was due to fewer repairs and maintenance on our midstream assets.

General and administrative expenses. General and administrative expenses include the costs of our employees, related benefits, field office expenses, professional fees, direct and indirect costs billed by the Manager in connection with the Services Agreement and other costs not directly associated with field operations. Our general and administrative expenses remained flat for the three months ended September 30, 2017 and 2016.

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Depreciation and amortization expense.    Gathering and transportation assets are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 5 to 15 years for equipment, and up to 36 years for gathering facilities. Our depreciation and amortization expense for the three months ended September30, 2017 and 2016 remained flat at $5.1 million.

Production Operating Results

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

	For the Three Months Ended
	September 30,
	2017		2016		Variance
Revenues:
Natural gas sales at market price	$	1,007	$	2,781	$	(1,774)	(64)	%
Natural gas hedge settlements		1,327		1,988		(661)	(33)	%
Natural gas mark-to-market activities		(1,555)		116		(1,671)	NM	(a)
Natural gas total		779		4,885		(4,106)	(84)	%
Oil sales at market price		4,517		3,192		1,325	42	%
Oil hedge settlements		3,989		5,621		(1,632)	(29)	%
Oil mark-to-market activities		(5,445)		(6,654)		1,209	18	%
Oil total		3,061		2,159		902	42	%
Natural gas liquids sales		514		264		250	95	%
Miscellaneous expense		8		(451)		459	NM	(a)
Total revenues		4,362		6,857		(2,495)	(36)	%
Operating expenses:
Lease operating expenses		1,585		2,650		(1,065)	(40)	%
Cost of sales		—		99		(99)	(100)	%
Production taxes		340		290		50	17	%
General and administrative		4,199		4,778		(579)	(12)	%
Unit-based compensation expense		631		90		541	NM	(a)
(Gain) loss on sale of assets		(2,546)		219		(2,765)	NM	(a)
Depreciation, depletion and amortization		1,756		2,411		(655)	(27)	%
Accretion expense		80		207		(127)	(61)	%
Total operating expenses		6,045		10,744		(4,699)	(44)	%
Operating loss	$	(1,683)	$	(3,887)	$	2,204	57	%

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

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	For the Three Months Ended
	September 30,
	2017		2016		Variance
Net production:
Natural gas production (MMcf)		399		1,024		(625)	(61)	%
Oil production (MBbl)		96		73		23	32	%
Natural gas liquids production (MBbl)		25		20		5	25	%
Total production (MBOE)		188		264		(76)	(29)	%
Average daily production (BOE/d)		2,043		2,870		(827)	(29)	%
Average sales prices:
Natural gas price per Mcf with hedge settlements	$	5.85	$	4.66	$	1.19	26	%
Natural gas price per Mcf without hedge settlements	$	2.52	$	2.72	$	(0.20)	(7)	%
Oil price per Bbl with hedge settlements	$	88.60	$	120.73	$	(32.13)	(27)	%
Oil price per Bbl without hedge settlements	$	47.05	$	43.73	$	3.32	8	%
Liquid price per Bbl without hedge settlements	$	20.56	$	13.20	$	7.36	56	%
Total price per BOE with hedge settlements	$	60.39	$	52.45	$	7.94	15	%
Total price per BOE without hedge settlements	$	32.12	$	23.63	$	8.49	36	%
Average unit costs per BOE:
Field operating expenses(a)	$	10.24	$	11.14	$	(0.90)	(8)	%
Lease operating expenses	$	8.43	$	10.04	$	(1.61)	(16)	%
Production taxes	$	1.81	$	1.10	$	0.71	65	%
General and administrative expenses	$	25.69	$	18.44	$	7.25	39	%
General and administrative expenses without unit-based compensation	$	22.34	$	18.10	$	4.24	23	%
Depreciation, depletion and amortization	$	9.34	$	9.13	$	0.21	2	%

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

Production.  For the three months ended September 30, 2017, 51% of our production was oil, 13% was NGLs and 36% was natural gas as compared to the three months ended September 30, 2016, where 28% of our production was oil, 7% was NGLs and 65% was natural gas. The production mix between the periods has shifted to a higher oil production in the current period as a result of recent asset divestitures. We expect natural gas production to decrease further as a percentage of total production due to the sale of our equity interests in the entities that owned our remaining Oklahoma production assets in a transaction that closed in July 2017. Additional natural gas production declines are anticipated due to the expected sale of non-operated production assets located in Texas. Combined production has decreased by 76 MBoe for the three months ended September 30, 2017, primarily due to the sale of our remaining operated production assets in Oklahoma (the “Oklahoma Production Divestiture”), partially offset by the Production Acquisition.

Oil, NGL and natural gas sales. Unhedged oil sales increased $1.3 million, or 42%, to $4.5 million for the three months ended September 30, 2017, compared to $3.2 million for the same period in 2016. NGL sales increased $0.2 million, or 95%, to $0.5 million for the three months ended September 30, 2017, compared to $0.3 million for the same period in 2016. Unhedged natural gas sales decreased $1.8 million, or 64%, to $1.0 million for the three months ended September 30, 2017, compared to $2.8 million for the same period in 2016. Total increase in oil, NGL and natural gas sales for the three months ended September 30, 2017 was primarily the result of increased production from the Production Acquisition and higher market prices, partially offset by our Oklahoma Production Divestiture.

Including hedges and mark-to-market activities, our total revenue decreased $2.5 million for the three months ended September 30, 2017, compared to the same period in 2016. This decrease was primarily the result of a $2.3 million decrease in settlements on oil and natural gas derivatives.

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The following tables provide an analysis of the impacts of changes in average realized prices and production volumes between the periods on our unhedged revenues from the three months ended September 30, 2017to the three months ended September 30, 2016 (dollars in thousands, except average sales price):

	Q3 2017	Q3 2016	Production	Q3 2016		Revenue
	Production	Production	Volume	Average		Increase/(Decrease)
	Volume	Volume	Difference	Sales Price		due to Production
Natural gas (Mcf)	399	1,024	(625)	$	2.72	$	(1,700)
Oil (MBbl)	96	73	23	$	43.73	$	1,005
Natural gas liquids (MBbl)	25	20	5	$	13.20	$	66
Total oil equivalent (MBoe)	188	264	(76)	$	23.63	$	(629)

		Q3 2017		Q3 2016				Revenue
		Average		Average	Average Sales		Q3 2017	Increase/(Decrease)
		Sales Price		Sales Price	Price Difference		Volume	due to Price
Natural gas (Mcf)	$	2.52	$	2.72	$	(0.20)	399	$	(80)
Oil (MBbl)	$	47.05	$	43.73	$	3.32	96	$	319
Natural gas liquids (MBbl)	$	20.56	$	13.20	$	7.36	25	$	184
Total oil equivalent (MBoe)	$	32.12	$	23.63	$	8.49	188	$	423

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 three months ended September 30, 2017by $0.6 million. 

Hedging activities. We apply mark-to-market accounting to our derivative contracts and the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in oil and natural gas sales. For the three months ended September 30, 2017, the non-cash mark-to-market loss was $7.0 million, compared to a loss of $6.6 million for the same period in 2016. The 2017 non-cash loss 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 quarter and settlements receivable) were $5.3 million for the three months ended September 30, 2017, compared to $7.6 million for the three months ended September 30, 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 $1.1 million, or 40%, to $1.6 million for the three months ended September 30, 2017, compared to $2.7 million during the same period in 2016. On a per unit basis, lease operating expenses were $8.43 per BOE, for the three months ended September 30, 2017, and $10.04 per BOE for the same period in 2016. The decreased lease operating expenses per BOE for the comparative periods were primarily the result of the divestiture of our Oklahoma assets.

General and administrative expenses. General and administrative expenses include the costs of our employees, related benefits, field office expenses, professional fees, direct and indirect costs billed by the Manager in connection with the Services Agreement and other costs not directly associated with field operations. General and administrative expenses, inclusive of unit compensation expense, remained flat for the three months ended September 30, 2017 and 2016.

Our general and administrative expenses were $25.69 per BOE for the three months ended September 30, 2017, compared to $18.44 per BOE for the same period in 2016. Excluding unit-based compensation, our general and administrative costs were $22.34 per BOE for the three months ended September 30, 2017, compared to $18.10 per BOE for the same period in 2016. This increase resulted from an increase of $0.1 million in asset management fees as well as a decrease of 76 BOE in total production.

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 oil, NGL and natural gas production increases or decreases, our depletion expense would increase or decrease as well.

Our depreciation, depletion and amortization expense for the three months ended September 30, 2017 was $1.8 million, or $9.34 per BOE, compared to $2.4 million, or $9.13 per BOE, for the same period in 2016. This decrease in the per BOE expense is primarily the result of the Production Acquisition offset by the Oklahoma Production Divestiture. Our non-oil and natural gas properties are depreciated using the straight-line basis.

Impairment expense. For the three months ended September 30, 2017 and 2016, we recorded no impairment charges.

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Nine months ended September 30, 2017 compared to nine months ended September 30, 2016 

Midstream Operating Results

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

	For the Nine Months Ended
	September 30,
	2017		2016		Variance
Revenues:
Gathering and transportation sales	$	39,621	$	41,130	$	(1,509)	(4)	%
Total gathering and transportation sales		39,621		41,130		(1,509)	(4)	%
Operating expenses:
Lease operating expenses		642		488		154	32	%
Transportation operating expenses		8,989		9,179		(190)	(2)	%
General and administrative		4,381		4,221		160	4	%
Depreciation and amortization expense		20,056		15,264		4,792	31	%
Accretion expense		203		187		16	9	%
Total operating expenses		34,271		29,339		4,932	17	%
Operating income	$	5,350	$	11,791	$	(6,441)	(55)	%

Gathering and transportation sales.  We consummated the acquisition of Western Catarina Midstream from Sanchez Energy and entered into the related gathering and processing agreement with Sanchez Energy in October 2015. On June 30, 2017, the gathering and processing agreement with Sanchez Energy was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018. During the nine months ended September 30, 2017, Sanchez Energy transported average daily production through the gathering system of approximately 11.2 MBbls/d of crude oil, 161.3 MMcf/d of natural gas and 11.2 MBbls/d of water. During the nine months ended September 30, 2016, Sanchez Energy transported average daily production through the gathering system of approximately 13.4 MBbls/d of crude oil, 185.5 MMcf/d of natural gas and an insignificant amount of water. The decrease in throughput was driven by a decrease in Sanchez Energy’s Catarina production by 1,743 MBoe over the nine months ended September 30, 2017 compared to the same period in 2016.

Lease operating expense.Lease operating expenses, which include ad valorem taxes, increased $0.1 million, to $0.6 million for the nine months ended September 30, 2017, compared to $0.5 million during the same period in 2016. This increase was a result of a crank shaft failure at a central processing facility.

Transportation operating expenses.   Our operating expenses generally consist of equipment rentals, chemicals, treating, metering fees, permit and regulatory fees, labor, minor maintenance, tools, supplies, and integrity management expenses. Our transportation operating expenses remained flat for the nine months ended September 30, 2017 and 2016.

General and administrative expenses. General and administrative expenses include the costs of our employees, related benefits, field office expenses, professional fees, direct and indirect costs billed by the Manager in connection with the Services Agreement and other costs not directly associated with field operations. Our general and administrative expenses remained flat for the nine months ended September 30, 2017 and 2016.

Depreciation and amortization expense    Gathering and transportation assets are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 5 to 15 years for equipment, and up to 36 years for gathering facilities. Our depreciation and amortization expense for the nine months ended September 30, 2017 and 2016 was $20.1 million and $15.3 million, respectively.  The increase was a result of revised useful lives used to depreciate the Western Catarina Midstream engines.

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Production Operating Results

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

	For the Nine Months Ended
	September 30,
	2017		2016			Variance
Revenues:
Natural gas sales at market price	$	5,413	$	7,289	$	(1,876)	(26)	%
Natural gas hedge settlements		2,624		6,514		(3,890)	(60)	%
Natural gas mark-to-market activities		(2,127)		(4,578)		2,451	54	%
Natural gas total		5,910		9,225		(3,315)	(36)	%
Oil sales at market price		15,433		9,347		6,086	65	%
Oil hedge settlements		6,133		13,673		(7,540)	(55)	%
Oil mark-to-market activities		954		(18,274)		19,228	NM	(a)
Oil total		22,520		4,746		17,774	NM	(a)
Natural gas liquid sales		1,473		784		689	88	%
Miscellaneous expense		(92)		(516)		424	82	%
Total revenues		29,811		14,239		15,572	NM	(a)
Operating expenses:
Lease operating expenses		9,957		11,430		(1,473)	(13)	%
Cost of sales		77		292		(215)	(74)	%
Production taxes		1,166		837		329	39	%
General and administrative		13,195		12,762		433	3	%
Unit-based compensation expense		1,951		1,619		332	21	%
(Gain) loss on sale of assets		(2,546)		219		(2,765)	NM	(a)
Depreciation, depletion and amortization		7,961		5,560		2,401	43	%
Asset impairments		4,688		1,309		3,379	NM	(a)
Accretion expense		444		714		(270)	(38)	%
Total operating expenses		36,893		34,742		2,151	6	%
Operating loss	$	(7,082)	$	(20,503)	$	13,421	65	%

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

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	For the Nine Months Ended
	September 30,
	2017		2016		Variance
Net production:
Natural gas production (Mcf)		2,302		3,405		(1,103)	(32)	%
Oil production (MBbl)		326		242		84	35	%
Natural gas liquids production (MBbl)		78		61		17	28	%
Total production (MBoe)		788		871		(83)	(10)	%
Average daily production (Boe/d)		2,886		3,179		(293)	(9)	%
Average sales prices:
Natural gas price per Mcf with hedge settlements	$	3.49	$	4.05	$	(0.56)	(14)	%
Natural gas price per Mcf without hedge settlements	$	2.35	$	2.14	$	0.21	10	%
Oil price per Bbl with hedge settlements	$	66.15	$	95.12	$	(28.97)	(30)	%
Oil price per Bbl without hedge settlements	$	47.34	$	38.62	$	8.72	23	%
Liquid price per Bbl without hedge settlements	$	18.88	$	12.85	$	6.03	47	%
Total price per Boe with hedge settlements	$	39.44	$	43.18	$	(3.74)	(9)	%
Total price per Boe without hedge settlements	$	28.32	$	20.00	$	8.32	42	%
Average unit costs per Boe:
Field operating expenses (a)	$	14.12	$	14.08	$	0.04	0	%
Lease operating expenses	$	12.64	$	13.12	$	(0.48)	(4)	%
Production taxes	$	1.48	$	0.96	$	0.52	54	%
General and administrative expenses	$	19.22	$	16.51	$	2.71	16	%
General and administrative expenses without unit-based compensation	$	16.74	$	14.65	$	2.09	14	%
Depreciation, depletion and amortization	$	10.10	$	6.38	$	3.72	58	%

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

Production.  For the nine months ended September 30, 2017, 41% of our production was oil, 10% was NGLs and 49% was natural gas as compared to the nine months ended September 30, 2016, where 28% of our production was oil, 7% was NGLs and 65% was natural gas. The production mix between the periods has shifted to a higher oil production in the current period as a result of recent asset divestitures. We expect natural gas production to decrease further as a percentage of total production due to the sale of our equity interests in the entities that owned our remaining operated Oklahoma production assets in a transaction that closed in July 2017. Additional natural gas production declines are expected due to the pending sale of  certain non-operated production assets located in Texas. Combined production has decreased by 83 MBoe for the nine months ended September 30, 2017, primarily due to the Mid-Continent and Oklahoma Production Divestiture, partially offset by the Production Acquisition.

Oil, NGL and natural gas sales. Unhedged oil sales increased $6.1 million, or 65%, to $15.4 million for the nine months ended September 30, 2017, compared to $9.3 million for the same period in 2016. NGL sales increased $0.7 million, or 88%, to $1.5 million for the nine months ended September 30, 2017, compared to $0.8 million for the same period in 2016. Unhedged natural gas sales decreased $1.9 million, or 26%, to $5.4 million for the nine months ended September 30, 2017, compared to $7.3 million for the same period in 2016. Total increase in oil, NGL and natural gas sales for the nine months ended September 30, 2017 was primarily the result of increased production from the Production Acquisition and higher market prices, partially offset by our Mid-Continent and Oklahoma Production Divestiture.

Including hedges and mark-to-market activities, our total revenue increased $15.6 million for the nine months ended September 30, 2017, compared to the same period in 2016. This increase was primarily the result of a $21.6 million increase in gains on mark-to-market activities plus a $6.1 million increase in oil sales, partially offset by a $11.4 million decrease in settlements on oil and natural derivatives.

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The following tables provide an analysis of the impacts of changes in average realized prices and production volumes between the periods on our unhedged revenues from the nine months ended September 30, 2017to the nine months ended September 30, 2016 (dollars in thousands, except average sales price):

	2017	2016	Production	2016		Revenue
	Production	Production	Volume	Average		Increase/(Decrease)
	Volume	Volume	Difference	Sales Price		due to Production
Natural gas (Mcf)	2,302	3,405	(1,103)	$	2.14	$	(2,360)
Oil (MBbl)	326	242	84	$	38.62	$	3,244
Natural gas liquids (MBbl)	78	61	17	$	12.85	$	218
Total oil equivalent (MBoe)	788	871	(83)	$	20.00	$	1,102

	2017		2016			Average		Revenue
	Average		Average		Sales Price		2017	Increase/(Decrease)
	Sales Price		Sales Price		Difference		Volume	due to Price
Natural gas (Mcf)	$	2.35	$	2.14	$	0.21	2,302	$	483
Oil (MBbl)	$	47.34	$	38.62	$	8.72	326	$	2,843
Natural gas liquids (MBbl)	$	18.88	$	12.85	$	6.03	78	$	470
Total oil equivalent (MBoe)	$	28.32	$	20.00	$	8.32	788	$	3,796

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 nine months ended September 30, 2017by $2.2 million. 

Hedging activities. We apply mark-to-market accounting to our derivative contracts and the full volatility of the non-cash change in fair value of our outstanding contracts is reflected in oil and natural gas sales. For the nine months ended September 30, 2017, the non-cash mark-to-market loss was $1.1 million, compared to a loss of $22.9 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 quarter and settlements receivable) were $8.7 million for the nine months ended September 30, 2017, compared to $20.2 million for the nine months ended September 30, 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 $1.4 million, or 13%, to $10.0 million for the nine months ended September 30, 2017, compared to $11.4 million during the same period in 2016. On a per unit basis, lease operating expenses were $12.64 per BOE, for the nine months ended September 30, 2017, and $13.12 per BOE for the same period in 2016. The decreased lease operating expenses per BOE for the comparative periods were primarily the result of our Mid-Continent and Oklahoma Production divestiture.

General and administrative expenses. General and administrative expenses include the costs of our employees, related benefits, field office expenses, professional fees, direct and indirect costs billed by the Manager in connection with the Services Agreement and other costs not directly associated with field operations. General and administrative expenses, inclusive of unit compensation expense, increased 6% to $15.2 million for the nine months ended September 30, 2017, compared to $14.4 million for the same period in 2016. This increase was primarily driven by an increase in asset management fees of $1.6 million.

Our general and administrative expenses were $19.22 per BOE for the nine months ended September 30, 2017, compared to $16.51 per BOE for the same period in 2016. Excluding unit-based compensation, our general and administrative costs were $16.74 per BOE for the nine months ended September 30, 2017, compared to $14.65 per BOE for the same period in 2016. This increase resulted from increased asset management fees noted above.

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 oil, NGL and natural gas production increases or decreases, our depletion expense would increase or decrease as well.

Our depreciation, depletion and amortization expense for the nine months ended September 30, 2017 was $8.0 million, or $10.10 per BOE, compared to $5.6 million, or $6.38 per BOE, for the same period in 2016. The increase in the per BOE expense is primarily the result of the Mid-Continent and Oklahoma Production Divestiture and 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.

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Impairment expense. For the nine months ended September 30, 2017, we recorded non-cash charges of $4.7 million, to impair certain of our producing oil and natural gas properties in Texas acquired as part of the Production Acquisition. During the same period in 2016, we recorded non-cash charges of $1.3 million to impair the value of our oil and natural gas fields located in Texas and Louisiana. The impairment expense recorded during the nine months ended September 30, 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.

Liquidity and Capital Resources

As of September 30, 2017, we had approximately $0.4 million in cash and cash equivalents and $11.0 million available for borrowing under the Credit Agreement in effect on such date. During the three months ended September 30, 2017, we paid approximately $2.0 million in cash for interest on borrowings under our Credit Agreement and approximately $20 thousand in cash for the commitment fee on undrawn commitments. For the nine months ended September 30, 2017, we paid approximately $5.4 million in cash for interest on borrowings under our Credit Agreement and approximately $100 thousand in cash for the commitment fee on undrawn commitments.

Our capital expenditures during the three and nine months ended September 30, 2017 were funded with cash on hand and borrowings under our Credit Agreement.  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.

Credit Agreement

We have entered into a credit facility 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 properties. 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 multiplied by 4.5.  Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral.  We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months.  Any increase in our borrowing base must be approved by all of our lenders. As of September 30, 2017, the borrowing base under the Credit Agreement was $215.6 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 for 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

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· 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 September 30, 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.

Sources of Debt and Equity Financing

As of September 30, 2017, the elected commitment amount under our Credit Agreement was set at $200.0 million and we had $189.0 million of debt outstanding under the facility, leaving us with $11.0 million in unused borrowing capacity. Our Credit Agreement matures on March 31, 2020.

Open Commodity Hedge Position

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” crude 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 crude 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 crude 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.

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The following tables as of September 30, 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— West Texas Intermediate (WTI)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price
2017	—	$	—	—	$	—	—	$	—	64,568	$	59.83	64,568	$	59.83
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
													758,656

MTM Fixed Price Basis Swaps– NYMEX (Henry Hub)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price
2017	—	$	—	—	$	—	—	$	—	124,160	$	3.79	124,160	$	3.79
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
													1,480,136

Net Cash Provided by Operations

We had net cash flows provided by operating activities for the nine months ended September 30, 2017 of $36.6 million, compared to net cash flow provided by operating activities of $30.8 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 $4.9 million, as well as return from equity investment greater than equity earnings for the period of $0.9 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 Western Catarina Midstream, 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 Western Catarina Midstream, as well as the market prices of oil and natural gas and our hedging program.

Net Cash Used in Investing Activities

We had net cash flows used in investing activities for the nine months ended September 30, 2017 of $32.6 million, consisting of $30.3 million related to midstream activities, including pipeline construction, and contributions to Carnero Processing and Carnero Gathering totaling $10.5 million.  These outflows were offset by $7.0 million related to proceeds from sales of oil and natural gas properties and final settlement of the Production Acquisition.

We had net cash flows used in investing activities for the nine months ended September 30, 2016 of $42.7 million, consisting of $40.0 million related to midstream activities, including pipeline construction and contributions to Carnero Processing and Carnero Gathering, and $2.7 million related to the development of oil and natural gas properties in the Palmetto Field in Gonzales County.

Net Cash Provided by (Used in) Financing Activities

Net cash flows used in financing activities was $4.6 million for the nine months ended September 30, 2017. During the nine months ended September 30, 2017, we had borrowings under our Credit Agreement of $45.5 million and proceeds from issuance of common units of $1.3 million. We distributed $22.8 million and $18.5 million to Class B preferred unit holders and common unit holders, respectively, during the same period.  Additionally, we paid $0.6 million in offering costs and repaid $9.5 million of borrowings.

Net cash flows provided by financing activities was $5.9 million for the nine months ended September 30, 2016. During the nine months ended September 30, 2016, we had borrowings under our Credit Agreement of $39.0 million. We distributed $24.9 million and $4.8 million to Class B preferred unit holders and common unit holders, respectively, during the same period. As part of our unit repurchase program, we used $2.9 million to repurchase and cancel 242,500 common units. Additionally, we paid $0.2 million in offering costs and $0.1 million related to units tendered by employees for tax withholding.

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In April 2017, we issued 84,577 common units in registered offerings for gross proceeds of approximately $1.3 million pursuant to a shelf registration statement originally filed with the SEC on March 6, 2015 as updated by that certain prospectus supplement filed with the SEC on April 6, 2017 (the “Shelf Registration Statement”). The Shelf Registration Statement allows the Partnership to sell up to $50.0 million of common units to fund general limited partnership purposes, including possible acquisitions. Net proceeds of $1.3 million from the equity issuance were used for general limited partnership purposes.

Off-Balance Sheet Arrangements

As of September 30, 2017, we had no off-balance sheet arrangements with third parties, and we maintained no debt obligations that contained 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. Our primary credit exposures result from the sale of oil and natural gas and our use of derivatives. Through September 30, 2017, we have not suffered any significant losses with our counterparties as a result of non-performance.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

As of September 30, 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 Part 1. Item 1. Note 2. “Basis of Presentation and Summary of Significant Accounting Policies” to the condensed consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

New Accounting Pronouncements

See Part 1. Item 1. Note 2. “Basis of Presentation and Summary of Significant Accounting Policies” to our condensed consolidated financial statements included in this report for information on new accounting pronouncements.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

We are not required to provide this disclosure as a smaller reporting company.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Principal Executive Officer and the Principal Financial Officer of the general partner of SNMP have evaluated the effectiveness of the disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of September 30, 2017 (the Evaluation Date). Based on such evaluation, the Principal Executive Officer and the Principal Financial Officer have concluded that, as of the Evaluation Date, our disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including the Principal Executive Officer and the Principal Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

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Changes in Internal Control over Financial Reporting

During the three months ended September 30, 2017, there were no changes in SNMP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, SNMP’s internal control over financial reporting.

Part II—Other Information

Item 1. Legal Proceedings

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

Item 1A. Risk Factors  

Consider carefully the risk factors under the caption “Risk Factors” under Part I, Item 1A in our 2016 Annual Report on Form 10-K, together with all of the other information included in this Quarterly Report on Form 10-Q; in our 2016 Annual Report; and in our other public filings, press releases, and public discussions with our management. Additional risks and uncertainties not currently known to us or that we currently deem immaterial may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

In connection with providing services under the Services Agreement for the second quarter 2017, the Partnership issued 170,497 common units to SP Holdings, LLC on August 31, 2017. See Note 12, “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.

No common units were purchased in the third quarter 2017.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information 

None.

Item 6. Exhibits

The exhibits required to be filed pursuant to the requirements of Item 601 of Regulation S-K are set forth in the exhibit index accompanying this form 10-Q and are incorporated herein by reference.

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EXHIBIT INDEX

Exhibit Number	Description
2.1*,***	Purchase and Sale Agreement between Sanchez Midstream Partners LP and Dallas Petroleum Group, LLC dated October 12, 2017.
10.1*	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.
31.1*	Certification of Principal Executive Officer of Sanchez Midstream Partners GP LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer of Sanchez Midstream Partners GP LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Principal 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 Principal Financial 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.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*Filed herewith.

**Furnished herewith.

***The exhibits and schedules to the Purchase and Sale Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S- K. The Company will furnish copies of such omitted exhibits and schedules to the Securities and Exchange Commission upon request. Descriptions of such exhibits and schedules are set forth within the body of the Purchase and Sale Agreement.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, Sanchez Midstream Partners LP, the Registrant, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SANCHEZ MIDSTREAM PARTNERS LP (REGISTRANT) BY: Sanchez Midstream Partners GP LLC, its general partner
Date: November 14, 2017	By	/s/ Charles C. Ward
		Charles C. Ward
		Chief Financial Officer and Secretary (Duly Authorized Officer and Principal Financial Officer)

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EX-2.1

Exhibit 2.1

October 12, 2017

Via E-MAIL

Sanchez Midstream Partners LP

Attn:  Colin McCulley

1000 Main Street, Suite 3000

Houston, Texas 77002

E-mail: cmcculley@sanchezog.com

RE: Purchase and sale agreement for property in South Texas

Dear Mr. McCulley:

Pursuant to our recent discussions and the Letter of Intent, this purchase and sale agreement (this “Agreement”), when executed by you, will set forth the terms and conditions under which Dallas Petroleum Group, LLC (“Buyer”) agrees to purchase from Sanchez Midstream Partners LP, including its related entities and affiliates (“Seller”), all of Seller’s right, title and interest in and to the Property (as defined below).  For good and valuable consideration, the receipt, adequacy and sufficiency of which are hereby acknowledged and confessed, Buyer and Seller enter into this Agreement and agree as follows:

1. The Property.  Subject to the terms and conditions of this Agreement, Seller agrees to sell, convey and assign to Buyer, and Buyer agrees to purchase, pay for and accept, all of Seller’s right, title and interest in and to the following (collectively, the “Property”):

(a) the oil, gas and/or mineral leases described on Exhibit A, including any ratifications, extensions and amendments thereto, along with any and all interests in the lands covered thereby, including, without limitation, all fee mineral interests, royalty interests, overriding royalty interests, non-participating royalty interests, executive rights, production payments, net profits interests, reversionary interests, operating interests and any other leasehold or mineral interests of any kind or nature (collectively, the “Leases”);

(b) all rights, benefits, privileges and interests in any unit or pooled area in which the Leases are included and are associated with, including, without limitation, those derived from any unitization, pooling, operating, communitization or other agreement or instrument, whether recorded or unrecorded, or from any declaration or order of any governmental authority (collectively, the “Units”);

(c) the oil, gas and condensate wells (whether producing, shut-in or temporarily abandoned, but excluding permanently abandoned wells), water source, water injection or other injection or disposal wells and systems located on, within the geographic boundaries of or otherwise affected by the Leases or the Units, including, without limitation, the wells described on Exhibit B (collectively, the “Wells”);

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(d) all tangible personal property, equipment, installations, fixtures, improvements and other appurtenances, including, without limitation, all machinery, facilities, flow lines, gathering lines, gas lines, water lines, pipelines, power lines, tubing, well pads, well heads, pumps, casing, caissons, motors, platforms, tank batteries, separators, treaters, rods, tanks, improvements, towers, SCADA equipment, radios, meters, computers, spare parts, compressors, pipe, vehicles, vessels, processing equipment and facilities, compression equipment and facilities and any and all other tangible personal property used solely in connection with the Leases, the Wells, the Units or the Permits and Easements (as defined below) (collectively, the “Equipment”);

(e) all permits, easements, rights-of-way, licenses, servitudes, surface leases, surface use agreements, surface fee tracts, fee surface interests, surface rights and any and all similar rights, benefits, privileges, obligations and interests used or held for use in connection with the Leases, the Wells, the Units or the lands appurtenant thereto, including, without limitation, those described on Exhibit C (collectively, the “Permits and Easements”);

(f) all agreements and contracts relating to the Property, including, without limitation, all existing and effective sales, purchase, exchange, gathering, transportation, processing and gas contracts, operating agreements, unit agreements, balancing agreements, farmout agreements, farmin agreements, exploration agreements and any and all other contracts, agreements and instruments insofar as they relate solely to the Property (collectively, the “Related Contracts”); and

(g) any and all original (or copies, if originals are not available) lease files, right-of-way files, division order files, well files, abstracts, title opinions, title files, contract files, revenue files, accounting files, payment files and any and all other files, information, and records, including, without limitation, all seismic and geological records, data, surveys, and interpretations, insofar as they relate solely to the Property (collectively, the “Records”).

2. Effective Time.  The effective time for the sale and purchase of the Property shall be 7:00 a.m. Central time on October 1, 2017 (the “Effective Time”).

3. Purchase Price.  The purchase price for the Property shall be Six Million and Two Hundred and Fifty Thousand U.S. Dollars ($6,250,000.00) (the “Purchase Price,” and the portion of the Purchase Price allocated to each of the Wells, as reflected on Exhibit B, is herein referred to as the “Allocated Value”), payable in cash to Seller at Closing (as defined below).  The Purchase Price shall be adjusted in the manner provided below and such adjustments shall be reflected in a settlement statement prepared by Buyer three (3) days prior to the Closing Date (using Buyer’s good faith estimated amounts where actual amounts are not available) (the “Settlement Statement”):

(a) The Purchase Price shall be adjusted upward as follows:

(i) an amount equal to all prepaid expenses attributable to the Property that are actually paid, out-of-pocket by Seller, prior to Closing that are attributable to periods from and after the Effective Time;

(ii) an amount equal to all verified expenditures attributable to the Property that are actually paid, out-of-pocket by Seller, in connection with the operation of the Property for work actually performed from and after the Effective Time;

(iii) the amount of proceeds, benefits, income or revenues received by Buyer for the sale of hydrocarbons produced that are attributable to periods before the Effective Time;

2

(iv) an amount equal to the imbalances owed to Seller set forth on Exhibit D, in full and final satisfaction of all imbalance obligations owed to Seller; and

(v) any other amount mutually agreed upon in writing by Seller and Buyer.

(b) The Purchase Price shall be adjusted downward as follows:

(i) the amount of proceeds, benefits, income or revenues received by Seller for the sale of hydrocarbons produced from and after the Effective Time;

(ii) an amount equal to all expenses attributable to the Property paid or incurred by Buyer, or on behalf of Buyer, that are attributable to periods prior to the Effective Time;

(iii) an amount equal to all unpaid expenses, including but not limited to all ad valorem taxes, real property taxes, and personal property taxes, attributable to the Property incurred by Seller, or on behalf of Seller, prior to Closing that are attributable to periods prior to the Effective Time; provided, however, that any such taxes which are calculated based on the value or amount of production during a given period shall be apportioned to the period during which such production occurred; regardless of the date on which such taxes are assessed and/or payable;

(iv) an amount equal to the Title Defect Amount (as defined below) for any uncured Title Defects;

(v) the Allocated Value for any Property excluded by Buyer pursuant to Section 6 or Section 7(d) below; and

(vi) any other amount mutually agreed upon in writing by Seller and Buyer.

4. Earnest Money Deposit.  Upon the parties’ execution of this Agreement, Buyer shall deliver to a mutually agreeable escrow agent between Buyer and Seller an earnest money deposit of Two Hundred and Fifty Thousand Dollars ($250,000.00).  The earnest money deposit shall be applied to the Purchase Price such that upon Closing (defined below), the Purchase Price shall be reduced accordingly.  If, however, the parties fail to close the transaction contemplated herein for any reason related to an unfulfilled condition to closing set forth in Sections 11(b)(i), (ii) and (iii), the earnest money deposit shall be returned to Buyer.  If the conditions to Closing set forth in Sections 11(b)(i), (ii) and (iii) are satisfied prior to Closing, then the earnest money deposit shall be retained by Seller.

5. Access.  Upon execution of this Agreement, Seller shall make available and grant access to Buyer and its representatives, employees, and consultants, during normal business hours, and at other mutually agreeable times prior to Closing, to (i) the Related Contracts, the Records, all title records (including, without limitation, title opinions, curative title documents, and run sheets) and all revenue, cost accounting, payment and other similar records related to the Property and (ii) the Leases, the Units, the Wells, Permits and Easements and all other Property. 

6. Environmental Conditions.  Buyer shall have the right, in its sole judgment, to conduct all necessary environmental assessments, analysis and tests on the Property (other than environmental sampling or other invasive environmental investigation) in order to determine whether (a) there exists any condition with respect to the air, soil, subsurface, surface waters, ground waters and/or sediment that causes Seller or any of its affiliates not to be in compliance with any Environmental Law or (b) there exists any condition, environmental pollution, contamination or degradation on the Property that would require remediation under any Environmental Law (each, an “Environmental Condition”).  Buyer shall have the

3

right in its sole and absolute discretion to exclude any portion of the Property from the transaction contemplated by this Agreement that is affected by an Environmental Condition.  As used herein, the term “Environmental Law” means any statute, law, ordinance, rule, regulation, code, order, injunction or decree issued by any federal, state or local governmental authority in effect on or before the Effective Time relating to the control of any pollutant or protection of the air, water, land or environment or the release or disposal of hazardous materials, hazardous substances or waste materials, including, without limitation, the federal Oil Pollution Act (OPA), the federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), the federal Resource Conservation and Recovery Act (RCRA), the federal Clean Water Act, the Toxic Substances Control Act (TSCA), the Hazardous Materials Transportation Act (49 USC § 5101 et seq.), the Texas Health and Safety Code, the Texas Water Code (TWC), the Texas Natural Resources Code, and the federal, state and local rules, regulations, ordinances, orders and governmental directives implementing such statutes.

7. Title Matters.  

(a) Title Defects.  As used herein, the term “Title Defect” shall mean any lien, encumbrance, defect or failure of Seller’s ownership of all or a portion of the Property that causes Seller not to have Defensible Title.  As used herein, the term “Defensible Title” shall mean title to the Property (on a Property-by-Property basis) that:

(i) entitles Seller to receive not less than the net revenue interest for each of the Wells, as set forth in Exhibit B;  

(ii) obligates Seller to bear not more than the working interest for each of the Wells, as set forth in Exhibit B; and

(iii) is free and clear of all mortgages, liens, encumbrances and defects, other than such that would not materially interfere with operations of the Property.

(b) Notice of Title Defects.  If Buyer determines that all or a portion of the Property is subject to any Title Defect, then Buyer may deliver to Seller written notice of such Title Defects on or before the date that is five (5) business days prior to the Closing Date.  Seller shall have the right, but not the obligation, to attempt to cure any asserted Title Defects until before three (3) days prior to the Closing Date.

(c) Title Defect Amount.  If any Title Defect is not cured or removed prior to delivery of the Settlement Statement by Buyer and Buyer does not waive such Title Defect, then the Purchase Price payable at Closing by Buyer shall be reduced pursuant to Section 3(b)(iv) by an amount equal to the following (the “Title Defect Amount”):

(i) if Buyer and Seller agree on the amount, then that amount shall be the Title Defect Amount;

(ii) if the Title Defect represents a decrease in (A) the actual net revenue interest for any Well, below (B) the net revenue interest set forth in Exhibit B for such Well (and there is a corresponding decrease in the working interest for such Well below the working interest set forth in Exhibit B), then the Title Defect Amount shall be the product of (y) the Allocated Value of such Well multiplied by (z) one (1), minus a fraction, the numerator of which is the actual net revenue interest for such Well and the denominator of which is the net revenue interest for such Well set forth in Exhibit B;

(iii) if the Title Defect consists of a lien, encumbrance or other charge that is

4

undisputed and liquidated in amount, the Title Defect Amount shall be the undisputed and liquidated amount necessary to be paid to remove the Title Defect; and

(iv) if the Title Defect is of a type not described above in subsections (i) through (iii), the Title Defect Amount shall be an amount that fairly and reasonably compensates Buyer for such Title Defect.

Provided,  however, that in the event Seller and Buyer cannot agree on Title Defect Amount, then the amounts shall be resolved by a dispute resolution process using a single impartial arbitrator, with at least ten (10) years’ experience in oil and gas title issues, to be selected by agreement of Seller and Buyer, or, in the event Buyer and Seller cannot agree on an arbitrator, such arbitrator shall be selected by the Dallas office of the American Arbitration Association.  The arbitrator’s decision as to the Title Defect Amount shall be final and not appealable.  Buyer and Seller shall each bear its own attorneys’ fees and costs in such arbitration.  Such arbitration shall be conducted in Fort Worth, Texas.  Once appointed, the arbitrator shall not have any ex parte communications with any of the affected parties.

(d) Removal of Title Defect Property.  In the event any Title Defect Amount for a Property subject to a Title Defect, as determined by Section 7(c) above, exceeds twenty-five percent (25%) of the Allocated Value associated with such Property, Buyer shall have the right to remove such Property from the transactions contemplated by this Agreement and reduce the Purchase Price by the Allocated Value of such Property by providing written notice to Seller prior to Closing.   

8. Reciprocal Representations and Warranties.  By their execution of this Agreement, Seller and Buyer each represent and warrant to the other that the following statements are true and accurate as to itself, in each case, as of the execution date of this Agreement and the Closing Date:

(a) Legal Entity Authority; Requisite Approvals.  If such party is not a natural person, such party is duly formed, validly existing and in good standing under the laws governing its organization.  If such party is a natural person, such party has all requisite and legal capacity to enter into this Agreement and perform his or her obligations hereunder.  Such party has all requisite power and authority to own its interest in the Property and to carry on its business as now conducted.  If such party is not a natural person, such party is, or will be, duly licensed or qualified to do business and is in good standing in each jurisdiction in which it carries on business or in which the Property is located as such qualification is required by law.

(b) Validity of Obligation.  This Agreement and all other transaction documents it is to execute and deliver at Closing: (i) have been, or at Closing will be, duly executed by its authorized representatives; (ii) constitute its valid and legally binding obligations subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium, and similar laws affecting creditors’ rights generally and subject to general principles of equity; and (iii) upon execution, are enforceable against it in accordance with their respective terms.

(c) No Violation of Restrictions.  Its execution, delivery and performance of the transaction contemplated by this Agreement and all other transaction documents it is to execute and deliver under the terms of this Agreement do not, or will not as of the Closing, conflict with or violate any agreement or instrument to which it is a party or by which it is bound, other than releases of liens on the Property to be obtained prior to Closing and consents contemplated by Section 9(a).  Its execution, delivery and performance of the transaction contemplated by this Agreement and all other transaction documents it is to execute and deliver under the terms of this Agreement do not violate any law, rule, regulation, ordinance, judgment, decree or order to which it or the Property or any portion thereof is subject.

(d) Bankruptcy.  There are no bankruptcy, reorganization or receivership proceedings

5

pending, being contemplated by, or to its actual knowledge, threatened against it.

(e) Brokers’ Fees.  It has not incurred any obligation for brokers’, finders’ or similar fees for which the other party hereto would be liable.

9. Seller’s Representations and Warranties.  By its execution of this Agreement, Seller represents and warrants to Buyer that the following statements are true and accurate, in each case, as of the execution date of this Agreement and the Closing Date: 

(a) Consents and Preferential Purchase Rights.  Except for those identified in writing and provided to Buyer, there are no restrictions on assignment (including requirements for consents from third parties to any assignment), preferential purchase rights or similar arrangements applicable to the Property that, in each case, Seller is required to obtain in connection with the transfer of the Property by Seller to Buyer or the consummation of the transaction contemplated by this Agreement or any transactions related hereto (excluding consents ordinarily obtained after Closing from a governmental authority, each of which have been identified in writing and provided to Buyer).

(b) Payments.  Seller has timely and properly paid all royalty interests, overriding royalty interests, working interests and other payments on production from the Property.

(c) Taxes.  All ad valorem, real property, severance and other similar taxes due and payable by Seller with respect of the Property or production therefrom prior to the Effective Time have been paid, except ad valorem taxes for the accounting year in which the Closing occurs which shall be apportioned as of the Effective Time between Buyer and Seller and reflected in the adjusted Purchase Price at Closing.

(d) Suits.  There is no action, suit, proceeding, claim, investigation or inquiry by any person, entity, administrative agency or governmental body and no legal, administrative, or arbitration proceeding pending or, to Seller’s knowledge, threatened, in each case, against the Property or against the Seller with respect to the Property.

(e) Exhibit Information; Leases.  The information set forth on Exhibit A and Exhibit B is true and correct, and all of the Leases are in full force and effect.

(f) Environmental.  There are no material Environmental Conditions associated with the Property other than those identified in writing and provided to Buyer.

(g) Related Contracts.  Copies of all Related Contracts (and any amendments thereto) that are not cancelable within 30 days and can reasonably be expected to involve annual expenditure payments in excess of $100,000 have been made available by Seller to Buyer prior to the execution of this Agreement.  All such Related Contracts are in full force and effect (subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium, and similar laws affecting creditors’ rights generally and subject to general principles of equity), and no party to such Related Contracts is in default or otherwise in breach with respect to any of its material obligations under such Related Contracts. 

(h) P & A Obligations.  Other than those identified in writing and provided to Buyer, there exist no Wells that (i) Seller is currently obligated by applicable law or contract to plug and abandon or (ii) have been plugged and abandoned in a manner that does not comply in all material respects with applicable laws and rules, regulations, permits, judgments, orders and decrees of any court or the applicable federal and state regulatory authorities.

6

(i) Suspense Funds.  All funds held in suspense with respect to the Property as of the Effective Time are set forth on Schedule 9(i), and have been placed and maintained in suspense in compliance with all applicable laws and contracts. 

(j) Imbalances.  There are no production or pipeline imbalances existing as of the Effective Time with respect to the Property, nor any rights or obligations as to future cash, gas or product balancing as a result of production or pipeline delivery imbalances.

10. Buyer’s Representations and Warranties.  By its execution of this Agreement, Buyer represents and warrants to Seller that the following statements are true and accurate, in each case, as of the execution date of this Agreement and the Closing Date: 

(a) Adequacy of Funds.  Buyer has, or on or before November 13, 2017, will have, sufficient readily available funds to pay the Purchase Price.

(b) Nature of Assets.  BUYER ACKNOWLEDGES THAT THE PROPERTY BEING TRANSFERRED TO BUYER IS BEING ACCEPTED BY BUYER IN ITS “AS IS, WHERE IS” CONDITION AND STATE OF REPAIR, AND WITH ALL FAULTS AND DEFECTS, WITHOUT, SUBJECT TO THE EXCEPTION BELOW, ANY REPRESENTATION, WARRANTY OR COVENANT OF ANY KIND OR NATURE, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, BUT NOT LIMITED TO, WARRANTIES OF MARKETABILITY, QUALITY, CONDITION, CONFORMITY TO SAMPLES, MERCHANTABILITY AND/OR FITNESS FOR A PARTICULAR PURPOSE, ALL OF WHICH ARE EXPRESSLY DISCLAIMED BY SELLER AND WAIVED BY BUYER, EXCEPT FOR THE REPRESENTATIONS AND WARRANTIES OF SELLER SET FORTH IN THIS AGREEMENT.  BUYER RECOGNIZES THAT THE PROPERTY HAS BEEN USED FOR OIL AND GAS DRILLING, COMPLETING, FRACTURING, PRODUCTION, GATHERING, PIPELINE, TRANSPORTATION, STORAGE AND RELATED OPERATIONS.  PHYSICAL CHANGES IN THE PROPERTY AND IN THE LANDS INCLUDED THEREIN MAY HAVE OCCURRED AS A RESULT OF SUCH USES.  THE PROPERTY ALSO MAY INCLUDE BURIED PIPELINES AND OTHER EQUIPMENT, THE LOCATIONS OF WHICH MAY NOT BE KNOWN BY SELLER OR READILY APPARENT BY A PHYSICAL INSPECTION OF THE PROPERTY.  IT IS UNDERSTOOD AND AGREED THAT BUYER SHALL HAVE INSPECTED PRIOR TO CLOSING (OR SHALL BE DEEMED TO HAVE WAIVED ITS RIGHT TO INSPECT) THE LEASES, EQUIPMENT, PIPELINES AND THE ASSOCIATED PREMISES INCLUDED IN THE PROPERTY AND SATISFIED ITSELF AS TO THEIR PHYSICAL AND ENVIRONMENTAL CONDITION, BOTH SURFACE AND SUBSURFACE, AND THAT BUYER SHALL ACCEPT ALL OF THE SAME IN THEIR “AS IS, WHERE IS” CONDITION AND STATE OF REPAIR, AND WITH ALL FAULTS AND DEFECTS, INCLUDING, BUT NOT LIMITED TO, THE PRESENCE OF NORM AND MAN-MADE MATERIAL FIBERS, SUBJECT TO THE REPRESENTATIONS AND WARRANTIES OF SELLER SET FORTH IN THIS AGREEMENT. 

11. Closing. 

(a) Time and Place.  The closing of the transactions contemplated hereby (the “Closing”) shall occur at 10:00 a.m. Central time on or before November 13, 2017 (the “Closing Date”) remotely via the electronic exchange of Closing deliverables (with originals to follow), or at such other time and place or in such other manner as the parties may mutually agree.  Prior to Closing, Seller shall maintain and operate the Property in a good and workmanlike manner consistent with prudent oilfield practices.

(b) Buyer’s Closing Conditions.  Buyer’s obligation to proceed to Closing is, at Buyer’s election, subject to the fulfillment of each of the following conditions, prior to or at Closing:

7

(i) All representations and warranties of Seller contained in this Agreement shall be true and correct in all respects as of the Closing Date as if such representations and warranties were made as of the Closing Date, and Seller shall have performed and satisfied all covenants and fulfilled all conditions required by this Agreement.

(ii) There are no material Environmental Conditions associated with the Property.

(iii) The aggregate downward adjustment to the Purchase Price due to any Title Defects and Environmental Conditions does not exceed five percent (5%) of the Purchase Price.

(iv) Seller shall deliver to Buyer a recordable release of all mortgages, security interests or other similar burdens on the Property, reasonably satisfactory to Buyer.

(v) Seller has executed or delivered, as applicable, all of the items listed in Section 11(d)(i),  (ii),  (iii),  (v), and (vi) below.

Notwithstanding anything to the contrary, Buyer may, in its sole discretion, terminate this Agreement if any or all of the conditions set forth in this Section 11(b) have not been satisfied as of November 13, 2017. 

(c) Seller’s Closing Conditions.  Seller’s obligation to proceed to Closing is, at Seller’s election, subject to the fulfillment of each of the following conditions, prior to or at Closing:

(i) All representations and warranties of Buyer contained in this Agreement shall be true and correct in all respects as of the Closing Date as if such representations and warranties were made as of the Closing Date, and Buyer shall have performed and satisfied all covenants and fulfilled all conditions in all material respects required by this Agreement.

(ii) Buyer has executed or delivered, as applicable, all of the items listed in Section 11(d)(i),  (ii),  (iii),  (iv), and (v) below.

Notwithstanding anything to the contrary, Seller may, in its sole discretion, terminate this Agreement if any or all of the conditions set forth in this Section 11(c) have not been satisfied as of November 13, 2017.

(d) Closing Deliverables.  At Closing, the following events shall occur, each being a condition precedent to the other and each being deemed to occur simultaneously:

(i) Conveyance.  Seller and Buyer shall each execute, acknowledge and deliver a Conveyance, Assignment and Bill of Sale (the “Assignment”), substantially similar to that set forth in Exhibit E, which shall convey unencumbered and defensible title to the Property to Buyer with a special warranty of Defensible Title by, through or under Seller, but not otherwise.

(ii) Governmental Conveyances.  Seller and Buyer shall each execute, acknowledge and deliver any other appropriate assignments, bills of sale, deeds or instruments necessary to transfer the Property to Buyer, including any conveyances on official forms and related documentation required by governmental agencies or governmental regulations.

(iii) Settlement Statement.  Seller and Buyer shall each execute and deliver the Settlement Statement.

(iv) Purchase Price.  Buyer shall deliver to Seller the Purchase Price as adjusted

8

and as indicated in the Settlement Statement pursuant to Section 3, by wire transfer in immediately available funds to an account designated in writing by Seller.

(v) Release Instruments.  Seller shall furnish evidence acceptable to Buyer of release of all liens, claims, security interests, mortgages, charges, encumbrances, or other similar burdens affecting the Property or any part thereof.

(vi) Non-Foreign Affidavit.  Seller shall execute and deliver a Non-Foreign Affidavit in the form attached as Exhibit F.

(vii) Further Assurances and Other Instruments.  Seller and Buyer agree to execute, acknowledge (if necessary) and deliver such further instruments (including, without limitation, instruments of conveyance and necessary governmental filings), and do such other acts as may be reasonably requested and necessary to effectuate the purposes of this Agreement.

12. Allocation of Revenues and Expenses.  The parties agree to make appropriate adjustments and take further action so that Seller receives all proceeds, receipts, credits and income attributable to the Property for all periods of time prior to the Effective Time, and so that Buyer receives all proceeds, receipts, credits and income attributable to the Property for all periods of time from and after the Effective Time.  All costs, expenses, disbursements, taxes and obligations attributable to the Property for all periods of time prior to the Effective Time shall be the responsibility of Seller, and all costs, expenses, disbursements, taxes and obligations attributable to the Property for all periods of time from and after the Effective Time shall be the responsibility of Buyer.  After the Closing, the parties will cooperate to have all proceeds received attributable to the Property be paid to the proper party hereunder and to have all expenditures to be made with respect to the Property be made by the proper party hereunder.

13. Miscellaneous.

(a) Survival.  All of the representations, warranties, covenants, and conditions under this Agreement shall survive the Closing for one (1) year and shall not merge into the Assignment. 

(b) Waiver of Consequential Damages.  WITH RESPECT TO ANY AND ALL LOSSES FOR WHICH INDEMNIFICATION MAY BE AVAILABLE HEREUNDER OR UNDER THE ASSIGNMENT, NO INDEMNIFYING PARTY SHALL HAVE ANY LIABILITY FOR ANY CONSEQUENTIAL, INDIRECT, PUNITIVE, EXEMPLARY OR SPECIAL DAMAGES WITH RESPECT TO ANY CLAIM FOR WHICH SUCH INDEMNIFYING PARTY MAY HAVE LIABILITY PURSUANT TO THIS AGREEMENT OR THE ASSIGNMENT; PROVIDED, HOWEVER, THAT THIS WAIVER SHALL NOT APPLY TO THE EXTENT SUCH CONSEQUENTIAL, INDIRECT, PUNITIVE, EXEMPLARY OR SPECIAL DAMAGES ARE AWARDED IN A PROCEEDING BROUGHT OR ASSERTED BY A THIRD-PARTY AGAINST AN INDEMNIFIED PARTY.

(c) Exhibits and Schedules.  The Exhibits attached to this Agreement are hereby incorporated into and made a part of this Agreement for all purposes. 

(d) Entire Agreement.  This Agreement and any other transaction documents executed in connection herewith (including, without limitation, the Assignment) constitute the entire understanding between Seller and Buyer, replacing and superseding any and all prior negotiations, discussions, arrangements, agreements and understandings between Seller and Buyer regarding the subject matter hereof (whether oral or written).

9

(e) Severability.  It is the intent of Seller and Buyer that the terms, conditions and provisions contained in this Agreement shall be severable.  Should any provision, in whole or in part, be held invalid as a matter of law, such holding shall not affect the other portions of this Agreement, and such portions that are not invalid shall be given effect without the invalid provision, if any.

(f) Amendment; Binding Effect.  This Agreement may not be amended, nor any rights hereunder waived except by an instrument in writing signed by a duly authorized representative of the party to be charged with such amendment or waiver and delivered by such party to the party claiming the benefit of such amendment or waiver.  This Agreement shall extend to and be binding upon and inure to the benefit of Seller and Buyer and their respective successors and assigns, and shall run with the Property. 

(g) Governing Law.  This Agreement shall be governed by and must be construed according to the laws of the State of Texas, without regard to conflicts of laws rules or principles that might direct the application of the law of another jurisdiction.

(h) Counterparts.  This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original instrument, and all of which, when taken together, shall constitute one and the same instrument.  This Agreement may be executed and delivered by facsimile or other reliable electronic means (such as portable document format), which such electronic signatures shall be considered binding for all purposes

(i) Section 1031 Exchange.  Seller and Buyer hereby agree that Seller shall have the right to assign all or a portion of its rights under this Agreement to a “Qualified Intermediary” (as that term is defined in Section 1.1031(k)-1(g)(4)(v) of the Treasury Regulations) in order to accomplish the transaction in a manner that will comply, either in whole or in part, with the requirements of a like kind exchange pursuant to Section 1031 of the Internal Revenue Code of 1986, as amended (the “Code”).  In the event that Seller assigns its rights under this Agreement pursuant to this Section 12(j), Seller agrees to notify Buyer in writing of such assignment at or before Closing.  If Seller assigns its rights under this Agreement for this purpose, Buyer agrees to: (a) consent to Seller’s assignment of its rights in this Agreement; and (b) pay the Purchase Price into a qualified escrow or qualified trust account at Closing as directed in writing.  Seller acknowledges and agrees that any assignment of this Agreement to a Qualified Intermediary shall not release Seller from any of its respective liabilities and obligations (including indemnity obligations) to the Buyer under this Agreement, and that no party hereto represents to any other party that any particular tax treatment will be given to a party as a result thereof.  Seller agrees that the Buyer will not incur any additional costs, expenses, fees or liabilities as a result of or connected with the like-kind exchange.

[remainder of page intentionally left blank/

signature page follows]

10

Please indicate your acceptance of this Agreement by executing in the space provided below and returning a scanned copy to me. 

Sincerely,
Dallas Petroleum Group, LLC
/s/ Mark Williams
Matt Williams
President
ACCEPTED AND AGREED:
Sanchez Midstream Partners LP
By:	Sanchez Midstream Partners GP,
	Its general partner
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	CFO & Secretary
Date:	10/12/2017

11

EX-10.1

Execution Version

Exhibit 10.1

SIXTH AMENDMENT
TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT

This SIXTH AMENDMENT TO THIRD AMENDED AND RESTATED CREDIT AGREEMENT (this “Amendment”), dated as of November 7, 2017, is among SANCHEZ MIDSTREAM PARTNERS LP, a Delaware limited partnership (the “Borrower”), the guarantors party hereto (the “Guarantors”), each of the Lenders party hereto, and ROYAL BANK OF CANADA, as administrative agent (in such capacity, the “Administrative Agent”), and as collateral agent (in such capacity, the “Collateral Agent”), and relates to that certain Third Amended and Restated Credit Agreement, dated as of March 31, 2015 (as amended, restated, modified or supplemented from time to time prior to the date hereof, the “Existing Credit Agreement”; and as amended hereby, the “Credit Agreement”), among the Borrower, the Lenders, the Administrative Agent, the Collateral Agent, and ROYAL BANK OF CANADA, as letter of credit issuer.

WITNESSETH:

WHEREAS, the parties hereto desire to make certain amendments to the Existing Credit Agreement to allow the Borrower to make quarterly distributions under Section 9.04(iii) of the Existing Credit Agreement for the fiscal quarter ended September 30, 2017, notwithstanding that the unused borrowing capacity at the time of such distributions may be less than 10% of the Loan Limit; and

WHEREAS, Section 12.02 of the Existing Credit Agreement provides that the Borrower and the Lenders may amend the Existing Credit Agreement and the other Loan Documents for certain purposes;

NOW, THEREFORE, in consideration of the premises contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound hereby, agree as follows:

Section 1. Definitions.  Unless otherwise defined in this Amendment, each capitalized term used in this Amendment has the meaning assigned to such term in the Credit Agreement.

Section 2. Amendments to the Credit Agreement.  The Credit Agreement is hereby amended as follows:

(a)Section 7.23 of the Credit Agreement is hereby amended by amending and restating the proviso at the end of clause (b) therein to read as follows:

“providedhowever, that the foregoing shall not apply to any quarterly cash distributions made by the Borrower for the fiscal quarter ending September 30, 2017 (to be paid on or before November 30, 2017),”

(b)Section 9.04 of the Credit Agreement is hereby amended by amending and restating clause (iii) therein to read as follows: 

“(iii) so long as (A) no Borrowing Base Deficiency, Default or Event of Default has

occurred and is continuing or would result therefrom (after giving effect to such dividend or distributions and any redetermination of the Borrowing Base as a result of such dividend) and (B) the Borrower would have unused borrowing capacity that can be accessed under this Agreement in an amount not less than 10% of the amount of the Loan Limit in effect at such time, the Borrower may declare and pay, or incur a liability to make, quarterly cash distributions in an amount equal to Available Cash (provided that subclause (B) shall not apply to any quarterly cash distributions made by the Borrower for the fiscal quarter ending September 30, 2017 (to be paid on or before November 30, 2017)),”

Section 3. Ratification.  Except as expressly amended, modified or waived herein, each of the Borrower and the Guarantors hereby ratifies and confirms all of the Obligations under the Credit Agreement and the other Loan Documents to which it is a party, and all references to the Credit Agreement, the Mortgages and the Notes in any of the Loan Documents shall be deemed to be references to the Credit Agreement, the Mortgages and the Notes as amended, modified or waived hereby.

Section 4. Effectiveness.  This Amendment shall become effective on the date (the “Amendment Effective Date”) on which each of the following conditions is satisfied:

(a)the Administrative Agent shall have received counterparts of this Amendment executed by the Administrative Agent, the Collateral Agent, the Borrower, the Guarantors and the Majority Lenders;

(b)the Borrower and each Guarantor shall have confirmed and acknowledged to the Administrative Agent and the Lenders, and by its execution and delivery of this Amendment the Borrower and each Guarantor do hereby confirm and acknowledge to the Administrative Agent and the Lenders, that (i) the execution, delivery and performance of this Amendment has been duly authorized by all requisite limited partnership or limited liability company action, as applicable, on the part of the Borrower or such Guarantor, as applicable, (ii) the Credit Agreement and each other Loan Document to which it is a party constitute valid and legally binding agreements enforceable against the Borrower or such Guarantor, as applicable, in accordance with their respective terms, except as such enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium, fraudulent transfer or other similar laws relating to or affecting the enforcement of creditors’ rights generally and by general principles of equity, (iii) the representations and warranties of the Borrower or such Guarantor, if any, set forth in the Credit Agreement and in each other Loan Document to which it is a party, shall be true and correct on and as of the Amendment Effective Date, except to the extent any such representations and warranties are expressly limited to an earlier date, in which case such representations and warranties shall have been true and correct as of such specified earlier date, (iv) no Default or Event of Default exists under the Credit Agreement or any of the other Loan Documents and (v) since December 31, 2014, there has been no event, development or circumstance that has had or could reasonably be expected to have a Material Adverse Effect; and

(c)the Borrower shall have paid all agreed fees to the extent due and payable in connection with this Amendment and paid or reimbursed the Administrative Agent for all its reasonable and documented out-of-pocket costs and expenses incurred in connection with the preparation and execution and delivery of this Amendment, in each case, to the extent provided in

2

Section 12.03 of the Credit Agreement.

Section 5. Governing Law.  THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

Section 6. Miscellaneous.

(a)On and after the Amendment Effective Date, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import, referring to the Credit Agreement, and each reference in each other Loan Document to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Existing Credit Agreement as amended or otherwise modified by this Amendment.  This Amendment shall constitute a Loan Document for purposes of the Credit Agreement.

(b)The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any default of the Borrower  or any Guarantor or any right, power or remedy of the Administrative Agent or the Lenders under any of the Loan Documents, nor constitute a waiver of any provision of any of the Loan Documents.

(c)Each of the Borrower and each Guarantor represents and warrants that as of the date hereof (i) it has the limited partnership or limited liability company power and authority to execute, deliver and perform the terms and provisions of this Amendment, has taken all necessary limited partnership or limited liability company action to authorize the execution, delivery and performance of this Amendment, delivery and performance of this Amendment does not and will not contravene the terms of the Borrower’s or such Guarantor’s, as applicable, organizational documents; (ii) it has duly executed and delivered this Amendment and this Amendment constitutes the legal, valid and binding obligation of the Borrower or such Guarantor enforceable in accordance with its terms, subject to the effects of bankruptcy, insolvency, fraudulent conveyance, reorganization and other similar laws relating to or affecting creditors’ rights generally and general principles of equity (whether considered in a proceeding in equity or law); (iii) no Default or Event of Default has occurred and is continuing; and (iv) no action, suit, investigation or other proceeding is pending or threatened before any arbitrator or Governmental Authority seeking to restrain, enjoin or prohibit or declare illegal, or seeking damages from the Borrower in connection with this Amendment or which could reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect.

Section 7. Severability.  Any provisions of this Amendment held by a court of competent jurisdiction to be invalid or unenforceable shall not impair or invalidate the remainder of this Amendment and the effect thereof shall be confined to the provisions so held to be invalid.

Section 8. Successors and Assigns.  This Amendment is binding upon and shall inure to the benefit of the Administrative Agent, the Collateral Agent, the Lenders, the Issuer, the Borrower and each Guarantor and their respective successors and assigns.

3

Section 9. Counterparts.  This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one agreement, and any of the parties hereto may execute this Amendment by signing any such counterpart.  Delivery of an executed counterpart of a signature page to this Amendment by telecopier or electronically by .pdf shall be effective as delivery of a manually executed counterpart of this Amendment.

Section 10. Headings.  The headings, captions and arrangements used in this Amendment are for convenience only and shall not affect the interpretation of this Amendment or any other Loan Document.

Section 11. Integration.  This Amendment represents the final agreement of the Borrower, each Guarantor, the Collateral Agent, the Administrative Agent, the Issuer, and the Lenders with respect to the subject matter hereof, and there are no promises, undertakings, representations or warranties by the Borrower, any Guarantor, the Administrative Agent, the Collateral Agent, the Issuer, nor any Lender relative to subject matter hereof not expressly set forth or referred to herein.

4

IN WITNESS WHEREOF, each of the parties hereto has caused this Amendment to be executed by its officer(s) thereunto duly authorized as of the date first above written.

SANCHEZ MIDSTREAM PARTNERS LP,
as Borrower
By:	SANCHEZ MIDSTREAM PARTNERS
	GP LLC, its general partner
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer

S - 1

SEP HOLDINGS IV, LLC,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer
CATARINA MIDSTREAM, LLC,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer
SECO PIPELINE, LLC,
as a Guarantor
By:	/s/ Charles C. Ward
Name:	Charles C. Ward
Title:	Chief Financial Officer

S - 2

ROYAL BANK OF CANADA,
as Administrative Agent and Collateral Agent
By:	/s/ Yvonne Brazier
Name:	Yvonne Brazier
Title:	Manager, Agency Services
ROYAL BANK OF CANADA,
as a Lender and the Issuer
By:	/s/ Emilee Scott
Name:	Emilee Scott
Title:	Authorized Signatory

S - 3

CAPITAL ONE, NATIONAL ASSOCIATION
as a Lender
By:	/s/ Michael Higgins
Name:	Michael Higgins
Title:	Senior Director

S - 4

EX-31.1

Exhibit 31.1

Sanchez midstream PARTNERS LP

CERTIFICATION

I, Gerry F. Willinger, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Sanchez Midstream Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2017

/s/ Gerry F. Willinger

Gerry F. Willinger

Chief Executive Officer

Sanchez Midstream Partners GP, LLC, as general partner of Sanchez Midstream Partners LP

(Principal Executive Officer)

EX-31.2

Exhibit 31.2

SANCHEZ MIDSTREAM PARTNERS LP

CERTIFICATION

I, Charles C. Ward, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Sanchez Midstream Partners LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2017

/s/ Charles C. Ward

Charles C. Ward

Chief Financial Officer and Secretary

Sanchez Midstream Partners GP, LLC, as general partner of Sanchez Midstream Partners LP

(Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Gerry F. Willinger, Chief Executive Officer of Sanchez Midstream Partners GP, LLC, as general partner of Sanchez Midstream Partners LP, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

(ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Sanchez Midstream Partners LP.

/s/ Gerry F. Willinger

Gerry F. Willinger

Chief Executive Officer

Sanchez Midstream Partners GP, LLC, as general partner of Sanchez Midstream Partners LP

(Principal Executive Officer)

Date: November 14, 2017

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

I, Charles C. Ward, Chief Financial Officer and Secretary of Sanchez Midstream Partners GP, LLC, as general partner of Sanchez Midstream Partners LP, certify pursuant to 18 U.S.C. Section 1350 adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 that to my knowledge:

(i) The accompanying Quarterly Report on Form 10-Q for the quarter ended September 30, 2017 fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934, as amended; and

(ii) The information contained in such report fairly presents, in all material respects, the financial condition and results of operations of Sanchez Midstream Partners LP.

/s/ Charles C. Ward

Charles C. Ward

Chief Financial Officer and Secretary

Sanchez Midstream Partners GP, LLC, as general partner of Sanchez Midstream Partners LP

(Principal Financial Officer)

Date: November 14, 2017

XML

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2017	Nov. 10, 2017
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Entity Registrant Name	Sanchez Midstream Partners LP
Entity Central Index Key	0001362705
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		14,778,192
Entity Current Reporting Status	Yes

XML

Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Revenues
Natural gas sales	$ 787	$ 4,434	$ 5,818	$ 8,709
Oil sales	3,061	2,159	22,520	4,746
Natural gas liquids sales	514	264	1,473	784
Gathering and transportation sales	14,234	12,997	39,621	41,130
Total revenues	18,596	19,854	69,432	55,369
Operating expenses:
Lease operating expenses	1,735	2,767	10,599	11,918
Transportation operating expenses	2,661	3,111	8,989	9,179
Cost of sales		99	77	292
Production taxes	340	290	1,166	837
General and administrative	5,614	6,286	17,576	16,983
Unit-based compensation expense	631	90	1,951	1,619
Loss (gain) on sale of assets	(2,546)	219	(2,546)	219
Depreciation, depletion and amortization	6,899	7,507	28,017	20,824
Asset impairments			4,688	1,309
Accretion expense	149	271	647	901
Total operating expenses	15,483	20,640	71,164	64,081
Other (income) expense
Interest expense, net	2,215	1,543	5,994	3,545
Gain on embedded derivatives		(30,012)		(43,204)
Earnings from equity investments	(2,873)	(1,124)	(4,397)	(1,136)
Other income				(49)
Total other (income) expenses	(658)	(29,593)	1,597	(40,844)
Total (income) expenses	14,825	(8,953)	72,761	23,237
Income (loss) before income taxes	3,771	28,807	(3,329)	32,132
Net income (loss)	3,771	28,807	(3,329)	32,132
Less:
Preferred unit distributions paid in common units			(2,625)
Preferred unit distributions	(8,750)	(12,250)	(24,500)	(29,750)
Preferred unit amortization	(463)	(6,608)	(1,300)	(20,379)
Net income (loss) attributable to common unitholders	$ (5,442)	$ 9,949	$ (31,754)	$ (17,997)
Net income (loss) per unit
Common units - Basic	$ (0.38)	$ 2.49	$ (2.29)	$ (5.06)
Common units - Diluted	$ (0.38)	$ 1.21	$ (2.29)	$ (5.06)
Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675

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Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 367	$ 957
Accounts receivable	731	1,212
Accounts receivable - related entities	6,729	5,987
Prepaid expenses	2,389	2,041
Fair value of derivative instruments	2,114	4,568
Total current assets	12,330	14,765
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	200,471	758,913
Gathering and transportation assets	183,681	152,209
Material and supplies		1,056
Less: accumulated depreciation, depletion, amortization and impairment	(162,403)	(689,358)
Oil and natural gas properties and equipment, net	221,749	222,820
Other assets
Intangible assets, net	175,530	185,766
Fair value of derivative instruments	3,187	3,964
Equity investments	120,303	111,614
Other non-current assets	585	776
Total assets	533,684	539,705
Current liabilities
Accounts payable and accrued liabilities	364	951
Accounts payable and accrued liabilities - related entities	6,482	7,046
Royalties payable	371	706
Fair value of derivative instruments	16	740
Total current liabilities	7,233	9,443
Other liabilities
Asset retirement obligation	7,796	13,579
Long-term debt, net of debt issuance costs	187,686	151,322
Fair value of derivative instruments	22	1,356
Other liabilities	4,049	4,270
Total other liabilities	199,553	170,527
Total liabilities	206,786	179,970
Commitments and contingencies (See Note 11)
Mezzanine equity
Class B preferred units, 31,000,887 and 29,296,441 units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	343,416	342,991
Partners' capital (deficit)
Common units, 14,773,192 and 13,447,749 units issued and outstanding as of September 30, 2017 and December 31, 2016, respectively	(16,518)	16,744
Total partners' capital (deficit)	(16,518)	16,744
Total liabilities and partners' capital	$ 533,684	$ 539,705

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Condensed Consolidated Balance Sheets (Parenthetical) - shares	Sep. 30, 2017	Dec. 31, 2016
Condensed Consolidated Balance Sheets
Class B preferred units, issued	31,000,887	29,296,441
Class B preferred units, outstanding	31,000,887	29,296,441
Units, issued	14,773,192	13,447,749
Units, outstanding	14,773,192	13,447,749

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Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Cash flows from operating activities:
Net income (loss)	$ (3,329)	$ 32,132
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	17,813	11,341
Amortization of debt issuance costs	391	377
Revisions to asset retirement obligation included in DD&A		(862)
Asset impairments	4,688	1,309
Accretion expense	647	901
Distributions from equity investments	5,329	750
Equity earnings in affiliate	(4,397)	(1,135)
Bad debt expense		35
(Gain)/loss from disposition of property and equipment	(2,386)	210
Total mark-to-market on commodity derivative contracts	(7,584)	2,664
Cash settlements on commodity derivative contracts	5,093	17,361
Cash settlements on terminated commodity derivative contracts	3,602	3,197
Premiums paid on derivative contracts		(3,197)
Unit-based compensation expense	2,646	2,042
Gain on embedded derivative		(43,204)
Amortization of intangible assets	10,204	10,345
Costs for plug and abandon activities	(46)	(142)
Changes in Operating Assets and Liabilities:
Accounts receivable	159	872
Accounts receivable - related entities	(1,042)	(5,025)
Prepaid expenses	(348)	(1,505)
Other assets	124	682
Accounts payable and accrued liabilities	6,416	(962)
Accounts payable and accrued liabilities - related entities	(1,033)	2,760
Royalties payable	(301)	(112)
Net cash provided by operating activities	36,646	30,834
Cash flows from investing activities:
Development of oil and natural gas properties	(148)	(2,706)
Proceeds from sale of oil and natural gas properties	5,510	38
Final settlement of oil and natural gas properties acquisition	1,468
Development of gathering and transportation assets	(29,058)
Purchases of equity investments	(10,380)	(40,002)
Net cash used in investing activities	(32,608)	(42,670)
Cash flows from financing activities:
Payments for offering costs	(611)	(226)
Proceeds from issuance of debt	45,500	39,000
Repayment of borrowings	(9,500)
Proceeds from issuance of preferred units		(87)
Repurchase of common units under repurchase program		(2,948)
Units tendered by employees for tax withholdings		(140)
Distributions to common unitholders	(18,530)	(4,815)
Proceeds from issuance of common units	1,290
Class B preferred unit cash distributions	(22,750)	(24,918)
Debt issuance costs	(27)
Net cash provided by (used in) financing activities	(4,628)	5,866
Net increase (decrease) in cash and cash equivalents	(590)	(5,970)
Cash and cash equivalents, beginning of period	957	6,571
Cash and cash equivalents, end of period	367	601
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	2,414	1,562
Change in asset retirement obligations	198
Cash paid during the period for interest	5,494	$ 3,085
Earnout liability	$ 221

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Condensed Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Class A Preferred Units	Common Units	Total
Partner's Capital (Deficit) at Dec. 31, 2015	$ 17,112	$ (45,285)	$ (28,173)
Partner's Capital (Deficit) (in shares) at Dec. 31, 2015	11,694,364	3,240,813
Units tendered by employees for tax withholding		$ (140)	(140)
Units tendered by employees for tax withholding (in shares)		(12,227)
Units forfeited by employees (in shares)		(2,000)
Unit-based compensation programs		$ 2,044	2,044
Unit-based compensation programs (in shares)		67,627
Issuance of common units, net of offering costs		$ 96,278	96,278
Issuance of common units, net of offering costs (in shares)		9,226,595
Class A Preferred Units converted to common units	$ (17,112)	$ 17,112
Class A Preferred Units converted to common units (in shares)	(11,694,364)	1,169,441
Common units retired via unit repurchase program		$ (2,948)	(2,948)
Common units retired via unit repurchase program (in shares)		(242,500)
Cash distributions to common unit holders		$ (6,696)	(6,696)
Distributions - Class B preferred units		(62,852)	(62,852)
Net income (loss)		19,231	19,231
Partner's Capital (Deficit) at Dec. 31, 2016		$ 16,744	16,744
Partner's Capital (Deficit) (in shares) at Dec. 31, 2016		13,447,749
Unit-based compensation programs		$ 2,648	2,648
Unit-based compensation programs (in shares)		212,481
Issuance of common units, net of offering costs		$ 9,124	9,124
Issuance of common units, net of offering costs (in shares)		719,671
Cash distributions to common unit holders		$ (18,530)	(18,530)
Common units issued as Class B Preferred distributions		$ 5,250	5,250
Common units issued as Class B Preferred distributions (in shares)		393,291
Distributions - Class B preferred units		$ (28,425)	(28,425)
Net income (loss)		(3,329)	(3,329)
Partner's Capital (Deficit) at Sep. 30, 2017		$ (16,518)	$ (16,518)
Partner's Capital (Deficit) (in shares) at Sep. 30, 2017		14,773,192

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Condensed Consolidated Statements of Changes in Partners’ Capital (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Condensed Consolidated Statements of Changes in Partners’ Capital
Offering costs	$ 0.6	$ 5.3

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Organization And Business

9 Months Ended

Sep. 30, 2017

Organization And Business

Organization And Business

1. ORGANIZATION AND BUSINESS

Organization

Sanchez Midstream Partners LP, a Delaware limited partnership, (together with our consolidated subsidiaries, “SNMP,” “we,” “us,” “our” or the “Partnership”) (formerly Sanchez Production Partners LP), is a growth oriented publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and production assets in North America. SNMP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). We have entered into a shared services agreement (the “Services Agreement”) with SP Holdings, LLC (the “Manager”), the sole member of our general partner, pursuant to which the Manager provides services that the Partnership requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. On March 6, 2015, the Company’s unitholders approved the conversion of Sanchez Production Partners LLC to a Delaware limited partnership and the name was changed to Sanchez Production Partners LP. On June 2, 2017, Sanchez Production Partners LP changed its name to Sanchez Midstream Partners LP. Manager owns the general partner of SNMP and all of SNMP’s incentive distribution rights. Our common units are currently listed on the NYSE American under the symbol “SNMP,” and were traded under the symbol “SPP” prior to our recent name change.

Historically, our operations have consisted of the production of proved reserves located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana. In October 2015, we consummated the acquisition of midstream assets in the Eagle Ford Shale from Sanchez Energy Corporation (“Sanchez Energy”) and entered into a 15-year gathering and processing agreement with Sanchez Energy. We also commenced a process to sell our production assets in the Mid-Continent region.  In July 2016, we sold a portion of our production assets in the Mid-Continent region and acquired a 50% equity interest in Carnero Gathering, LLC (“Carnero Gathering”). In November 2016, we completed a public offering of approximately 6,745,107 common units (which includes exercise of the underwriters’ option to purchase 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses.  Concurrent with the public offering, we completed a private placement of 2,272,727 common units representing limited partner interests for net proceeds of approximately $25.0 million. The combined proceeds were used to close the acquisition of a 50% equity interest in Carnero Processing, LLC (“Carnero Processing”) and the acquisition of working interests in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas and escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas. In July 2017, we sold our equity interests in the entities that owned our remaining operated Oklahoma production assets for cash consideration of $5.5 million, subject to customary post-closing adjustments, and assumption by the buyer of certain plugging and abandonment costs. In August 2017, we completed construction of the “SECO Pipeline,” a natural gas pipeline with 400 MMcf/d of capacity that is designed and used to transport dry gas from the Raptor Gas Processing Facility (defined below) to multiple markets in South Texas. On October 12, 2017, we signed a purchase and sale agreement to sell certain oil and natural gas properties in Texas.

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Basis Of Presentation And Summary Of Significant Accounting Policies

9 Months Ended

Sep. 30, 2017

Basis Of Presentation And Summary Of Significant Accounting Policies

Basis of Presentation and Significant Accounting Policies

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These unaudited condensed consolidated financial statements include the accounts of SNMP and our wholly owned subsidiaries.  All intercompany accounts and transactions have been eliminated in consolidation.  We conduct our business activities as two operating segments: the production of oil and natural gas and the midstream business, which includes Western Catarina Midstream (defined below).  Our management evaluates performance based on these two business segments.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (“SEC”).  Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”), have been condensed or omitted pursuant to those rules and regulations.  We believe that the disclosures made are adequate to make the information presented not misleading.  In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included.  The results of operations for the interim periods are not necessarily indicative of the results for the entire year. 

These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of SNMP and its subsidiaries included 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. 

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption.

In August 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which changes the recognition and presentation requirements of hedge accounting, including eliminating the requirement to separately measure and report hedge ineffectiveness, and presenting all items that affect earnings in the same income statement line item as the hedged item.  The ASU also provides new alternatives for applying hedge accounting.  This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018.  Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements.

In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods 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 December 2016, the FASB issued ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are effective upon issuance (December 2016).

In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is effective for public business entities for annual and interim periods 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 will be effective beginning with the first quarter 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 March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. The adoption of this guidance did not have a material impact on our consolidated financial statements.

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 not early adopt the standard although early adoption is permitted. The Partnership’s expectation is to apply the modified retrospective approach. As part of the assessment, the Partnership has formed an implementation work team, completed trainings on the new revenue recognition model and gathered a representative sample of material revenue contracts covering current revenue streams for which we are currently evaluating the impact under the new standard. The Company is currently collecting all remaining contracts and evaluating the impacts to its consolidated financial statements under the revised standards. In addition, the Company is evaluating the impacts of significant historical transactions under the new standard.

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates. 

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2017

Acquisitions and Divestitures

Acquisitions and Divestitures

3. ACQUISITIONS AND DIVESTITURES

Our acquisitions are accounted for under the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.” A business combination may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties obtained through our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions.

Texas Production Divestiture

On October 12, 2017, the Partnership entered into a purchase and sale agreement with Dallas Petroleum Group, LLC pursuant to which the Partnership has agreed to sell to Dallas Petroleum Group, LLC, on the closing date, specified oil and gas wells, leases and other associated assets and interests located in Texas (the “Texas Production Assets”) for cash consideration of approximately $6.3 million, subject to adjustment for title and environmental defects (the “Texas Production Divestiture”).  In addition, the buyer has agreed to assume all obligations relating to the assets, including all plugging and abandonment costs relating to the assets, that arose on or after October 1, 2017.  The Texas Production Divestiture is anticipated to close during the fourth quarter 2017. We anticipate reporting a gain on the sale during the fourth quarter 2017.  On October 12, 2017, a purchase and sale agreement entered into by a wholly owned subsidiary of the Partnership and Sendero Petroleum, LLC, dated June 30, 2017, relating to the sale of the Texas Production Assets, was terminated by the Partnership as a result of the closing not having occurred by the outside date specified therein.

Non-Operated Production Divestiture

On July 14, 2017, we entered into an agreement to assign certain non-operated production assets located in Oklahoma, as well as our equity interests in the entities that owned the assets, in exchange for agreeing upon the apportionment of certain shared litigation costs (the “Non-Operated Production Divestiture”). The assignment was effective as of July 14, 2017.

Oklahoma Production Divestiture

On May 10, 2017, we entered into a purchase and sale agreement to sell all of the Partnership’s equity interests in the entities that owned our remaining Oklahoma production assets for cash consideration of $5.5 million, subject to adjustment for title and environmental defects (the “Oklahoma Production Divestiture”), and assumption by the buyer of all obligations relating to the assets arising after the closing date and all plugging and abandonment costs relating to the assets arising prior to the closing date. The transaction closed July 17, 2017. We recorded a gain of $2.4 million on the sale during the third quarter 2017.

Carnero Processing Acquisition

On November 22, 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Processing from SN Midstream, LLC, a wholly owned subsidiary of Sanchez Energy (“SN Midstream”), for cash consideration of approximately $55.5 million and the assumption of approximately $24.5 million of remaining capital commitments to Carnero Processing (the “Carnero Processing Transaction”). The remaining 50% membership interests in Carnero Processing are owned by TPL SouthTex Processing Company LP, an affiliate of Targa Resources Group (“Targa”). Carnero Processing owns a cryogenic gas processing facility located in La Salle County, Texas that is operated by Targa (the “Raptor Gas Processing Facility”). See Note 10. “Investments” for additional information relating to the Carnero Processing Transaction.

The Partnership made capital contributions to Carnero Processing totaling $15.8 million between November 22, 2016 and September 30, 2017.

Production Acquisition

On November 22, 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 for aggregate cash consideration of approximately $24.2 million after approximately $2.8 million in normal and customary closing adjustments (the “Production Acquisition”). The effective date of the transaction was July 1, 2016. The Production Acquisition included initial conveyed working interests and net revenue interests which, for certain properties, escalated on January 1, 2017 and will escalate again on January 1, 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

On July 5, 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Gathering from SN Midstream for cash consideration of approximately $37.0 million, and the assumption of approximately $7.4 million of remaining capital commitments to Carnero Gathering (the “Carnero Gathering Transaction”).  In addition, the Partnership is required to pay SN Midstream a monthly earnout based on gas received from SN Catarina, LLC, a wholly owned subsidiary of Sanchez Energy (“SN Catarina”), at Carnero Gathering’s receipt points, as well as gas delivered and processed at the Raptor Gas Processing Facility for other producers. The remaining 50% membership interests in Carnero Gathering are owned by Targa. Carnero Gathering owns a gas gathering pipeline in the Western Eagle Ford in South Texas that is operated by Targa and interconnects with the Raptor Gas Processing Facility. See Note 10. “Investments” for additional information relating to the Carnero Gathering Transaction.

The Partnership made capital contributions to Carnero Gathering totaling $8.4 million between July 5, 2016 and September 30, 2017.

Mid-Continent Divestiture

On June 15, 2016, certain wholly owned subsidiaries of the Partnership entered into an agreement with Gateway Resources U.S.A., Inc. (“Gateway”) to sell substantially all of the Partnership’s operated production assets 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, subject to adjustment for title and environmental defects, effective as of August 1, 2016. In addition, Gateway agreed to assume all obligations relating to the assets arising after the effective date and all plugging and abandonment costs relating to the assets arising prior to the effective date. The Partnership closed the sale of this transaction on July 15, 2016. The Partnership recorded a $0.2 million loss related to an intangible asset balance comprised of marketing contracts from the 2007 Newfield acquisition which were included in the Mid-Continent Divestiture.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2017

Fair Value Measurements

Fair Value Measurements

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 September 30, 2017 (in thousands):

	Fair Value Measurements at September 30, 2017
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
Derivative assets (net)	$	—	$	5,263	$	—	$	5,263
Total net assets	$	—	$	5,263	$	—	$	5,263

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
Derivative assets (net)	$	—	$	6,436	$	—	$	6,436
Total net assets	$	—	$	6,436	$	—	$	6,436

As of September 30, 2017, and December 31, 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 8, “Asset Retirement Obligation.”

The following table summarizes the non-recurring fair value measurements of our assets as of September 30, 2017 (in thousands):

	Fair Value Measurements at September 30, 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 nine months ended September 30, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas properties 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 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) During 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 fair values of oil and natural gas properties were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) 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.

Fair Value of Financial Instruments

Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports.  The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below.

Credit Agreement – We believe that the carrying value of long-term debt for our Credit Agreement (defined below) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms.  The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties.  Our Credit Agreement is discussed further in Note 6, “Long-Term Debt.”

Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs.  Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate.  Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate derivatives as of September 30, 2017. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.

Embedded Derivative – 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. We therefore classified the fair value measurements of our embedded derivative as Level 3 inputs. 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 fixed and the provisions that required the bifurcation were removed.  At that time, the fair value of the derivative was transferred to mezzanine equity.

The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded derivative classified as Level 3 in the fair value hierarchy for the year ended December 31, 2016 (in thousands):

	December 31,
	2016
Beginning balance	$	(193,077)
Gain on embedded derivative		47,794
Transfer to mezzanine equity		145,283
Ending balance	$	—
Loss included in earnings related to derivatives still held as of December 31, 2016	$	—

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Derivative And Financial Instruments

9 Months Ended

Sep. 30, 2017

Derivative And Financial Instruments

Derivative And Financial Instruments

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 condensed 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 in natural gas sales and oil sales in the condensed consolidated statements of operations.

As of September 30, 2017, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:

Fixed Price Basis Swaps–West Texas Intermediate (WTI)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price
2017	—	$	—	—	$	—	—	$	—	64,568	$	59.83	64,568	$	59.83
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
													758,656

Fixed Price Swaps—NYMEX (Henry Hub)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price
2017	—	$	—	—	$	—	—	$	—	124,160	$	3.79	124,160	$	3.79
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
													1,480,136

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the nine months ended September 30, 2017 and the year ended December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Beginning fair value of commodity derivatives	$	6,436	$	31,018
Net gains (losses) on crude oil derivatives		7,087		(8,355)
Net gains (losses) on natural gas derivatives		497		1,116
Net settlements on derivative contracts:
Crude oil		(6,133)		(13,622)
Natural gas		(2,624)		(6,919)
Net premiums on derivative contracts		—		3,198
Ending fair value of commodity derivatives	$	5,263	$	6,436

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

		Amount of Gain (Loss) in Income
	Location of Gain (Loss)	Three Months Ended September 30,				Nine Months Ended September 30,
Derivative Type	in Income	2017		2016		2017		2016
Commodity – Oil Hedges	Oil sales	$	(1,456)	$	(1,032)	$	7,087	$	(4,600)
Commodity – Gas Hedges	Natural gas sales		(228)		2,104		497		1,936
		$	(1,684)	$	1,072	$	7,584	$	(2,664)

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 crude 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 September 30, 2017, and December 31, 2016, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant.

Embedded Derivative

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.

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the year ended December 31, 2016 (in thousands):

	December 31,
	2016
Beginning fair value of embedded derivative	$	(193,077)
Gain on embedded derivative		47,794
Transfer to mezzanine equity		145,283
Ending fair value of embedded derivative	$	—

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Long-Term Debt

9 Months Ended

Sep. 30, 2017

Long-Term Debt

Long-Term Debt

6. LONG-TERM DEBT

We have entered into a credit facility 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 properties.  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 multiplied by 4.5.  Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral.  We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months.  Any increase in our borrowing base must be approved by all of the lenders.  As of September 30, 2017, the borrowing base under the Credit Agreement was $215.6 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.

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 September 30, 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 for any violation of a financial covenant from the lenders, but there is no assurance that such waivers would be granted.

Debt Issuance Costs

As of September 30, 2017, and December 31, 2016, our unamortized debt issuance costs were $1.3 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 three months ended September 30, 2017 and 2016 were $0.1 million. Amortization of debt issuance costs recorded during the nine months ended September 30, 2017 and 2016 were $0.4 million.

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Oil And Natural Gas Properties And Related Equipment

9 Months Ended

Sep. 30, 2017

Oil And Natural Gas Properties And Related Equipment.

Oil And Natural Gas Properties And Related Equipment

7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT

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

	September 30,		December 31,
	2017		2016
Gathering and transportation assets
Midstream assets	$	183,681	$	152,209
Less: Accumulated depreciation and amortization		(24,983)		(15,020)
Total gathering and transportation assets	$	158,698	$	137,189

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

	September 30,		December 31,
	2017		2016
Oil and natural gas properties and related equipment
Property costs
Proved property	$	200,422	$	758,366
Unproved property		49		46
Land		—		501
Total property costs		200,471		758,913
Materials and supplies		—		1,056
Total		200,471		759,969
Less: Accumulated depreciation, depletion, amortization and impairments		(137,420)		(674,338)
Oil and natural gas properties and equipment, net	$	63,051	$	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.

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.

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.

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Depreciation, depletion and amortization of oil and natural gas-related assets	$	1,739	$	2,348	$	7,850	$	5,310
Depreciation, depletion and amortization of gathering and transportation-related assets		1,780		1,731		9,963		5,169
Amortization of intangible assets		3,380		3,428		10,204		10,345
Total depreciation, depletion and amortization		6,899		7,507		28,017		20,824
Asset impairments		—		—		4,688		1,309
Total	$	6,899	$	7,507	$	32,705	$	22,133

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 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.

For the three months ended September 30, 2017,  we recorded no impairment charges. For the nine months ended September 30, 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 three months ended September 30, 2016, we did not record impairment charges. For the nine months ended September 30, 2016, we recorded non-cash charges of $1.3 million, to impair our producing oil and natural gas properties in Texas and Louisiana acquired prior to the Eagle Ford acquisition.

Asset Retirement Obligation.  As described in Note 8, 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 nine months ended September 30, 2017 or 2016.

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Asset Retirement Obligation

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation

Asset Retirement Obligation

8. 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 or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method 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):

	September 30,		December 31,
	2017		2016
Asset retirement obligation, beginning balance	$	13,579	$	20,364
Liabilities added from acquisitions		198		912
Sold		(6,582)		(6,291)
Revisions to cost estimates		—		(2,399)
Settlements		(46)		(134)
Accretion expense		647		1,127
Asset retirement obligation, ending balance	$	7,796	$	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 and other facilities reduce the liability for AROs. During the nine months ended September 30, 2017, and the year ended December 31, 2016, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the nine months ended September 30, 2017, obligations were sold as part of the Oklahoma 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. Additional reductions in future abandonment obligations are expected in the fourth quarter 2017 as a result of the expected Texas Production Divestiture.

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Intangible Assets

9 Months Ended

Sep. 30, 2017

Intangible Assets

Intangible Assets

9. INTANGIBLE ASSETS

Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $175.5 million related to the gathering agreement with Sanchez Energy that was entered into as part of the acquisition of the Western Catarina gathering system (“Western Catarina Midstream”). Pursuant to the 15-year agreement, Sanchez Energy tenders all of its crude 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. During 2016, the intangible asset balance was reduced by $0.2 million due to marketing contracts from the 2007 Newfield acquisition which were included in the Mid-Continent Divestiture.

Amortization expense for the nine months ended September 30, 2017 and 2016 was $10.2 million and $10.3 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations.  Intangible assets as of September 30, 2017, and December 31, 2016 are detailed below (in thousands):

	September 30,		December 31,
	2017		2016
Beginning balance	$	185,766	$	199,741
Disposals		(32)		(219)
Amortization		(10,204)		(13,756)
Ending balance	$	175,530	$	185,766

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Investments

9 Months Ended

Sep. 30, 2017

Investments

Investments

10. INVESTMENTS

On July 5, 2016, the Partnership purchased a 50% membership interest in Carnero Gathering from SN Midstream 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 remaining 50% membership interests of Carnero Gathering are owned by an affiliate of Targa. During the nine months ended September 30, 2017, the Partnership made approximately $5.1 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $26.0 million in the Carnero Gathering joint venture. 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 the contract term of fifteen years and decrease earnings from Carnero Gathering. As part of the Carnero Gathering Transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered by other producers and processing by Carnero Processing. This earnout is considered as contingent consideration and its estimated fair value of $4.0 million was recorded on the balance sheet as a deferred liability as of September 30, 2017.  No earnout payments were made in the three or nine months ended September 30, 2017.

As of September 30, 2017, the Partnership had paid approximately $45.9 million for the Carnero Gathering Transaction related to the initial purchase price, acquisition costs and contributed capital to date. 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 Condensed Consolidated Balance Sheet. For the nine months ended September 30, 2017, the Partnership recorded earnings of approximately $4.7 million in equity investments from Carnero Gathering, which was offset by approximately $0.6 million related to the amortization of the contractual customer intangible asset. For the three months ended September 30, 2017, the Partnership recorded earnings of approximately $2.0 million in equity investments from Carnero Gathering, which was offset by approximately $0.2 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 Condensed Consolidated Statements of Operations. Cash distributions of $5.3 million were received during the nine months ended September 30, 2017.

On November 22, 2016, the Partnership purchased a 50% membership interest in Carnero Processing from SN Midstream 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 remaining 50% membership interests of Carnero Processing are owned by an affiliate of Targa. During the nine months ended September 30, 2017, the Partnership made $5.3 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $48.0 million in the Carnero Processing joint venture.

As of September 30, 2017, the Partnership had paid approximately $71.8 million for the Carnero Processing transaction related to the initial payment, acquisition costs 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 expenses of approximately $0.5 million in the “Earnings from equity investments” line within our consolidated statements of operations for the nine months ended September 30, 2017 and $1.0 million for the three months ended September 30, 2017.

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

	Nine Months Ended
	September 30,
	2017
Sales	$	57,406
Total expenses		46,734
Net income	$	10,672

	September 30,		December 31,
	2017		2016
Current assets	$	28,318	$	27,779
Noncurrent assets		190,100		152,112
Current liabilities		18,040		16,577

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Commitments And Contingencies

9 Months Ended

Sep. 30, 2017

Commitments And Contingencies

Commitments And Contingencies

11. COMMITMENTS AND CONTINGENCIES

As part of the Carnero Gathering Transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered and processed at Carnero Processing by other producers which began at the end of the second quarter 2017. This earnout has an approximate value of $4.0 million and was recorded on the balance sheet as a deferred liability as of September 30, 2017. We did not have any other material commitments and contingencies and no payments were made as of September 30, 2017.

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Related Party Transactions

9 Months Ended

Sep. 30, 2017

Related Party Transactions

Related Party Transactions

12. RELATED PARTY TRANSACTIONS

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, professionals, 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 additional one-year terms unless either Manager or the Partnership provides notice of termination to the other with at least 180 days’ notice.  During the nine months ended September 30, 2017, we expensed approximately $6.5 million to Manager pursuant to the Services Agreement.

Manager utilizes Sanchez Oil & Gas Corporation (“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, the President and Chief Operating Officer of our general partner, Eduardo A. Sanchez, one of our directors, 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.

In October 2015, the Partnership entered into a Firm Gathering and Processing Agreement with Sanchez Energy for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas is dedicated for gathering by Catarina Midstream, LLC (the “Gathering Agreement”). In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. 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 of September 30, 2017, and December 31, 2016, the Partnership had a net receivable from related parties of $6.7 million and $6.0 million, respectively, which are included in “Accounts receivable – related entities” in the condensed consolidated balance sheets. As of September 30, 2017, and December 31, 2016, the Partnership also had a net payable to related parties of $6.5 million and $7.0 million, respectively. The net receivables/payable as of September 30, 2017, and 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, development of gathering and transportation assets and obligations for general and administrative costs. 

In July 2016, we acquired 50% of the outstanding membership interests in Carnero Gathering from SN Midstream for cash consideration of approximately $37.0 million, and the assumption of approximately $7.4 million of remaining capital commitments to Carnero Gathering.  In addition, the Partnership is required to pay SN Midstream a monthly earnout based on gas received from SN Catarina at Carnero Gathering’s receipt points, as well as gas delivered and processed at the Raptor Gas Processing Facility for other producers. The remaining 50% of the membership interests are owned by an affiliate of Targa. Carnero Gathering operates a gas gathering pipeline in the Western Eagle Ford in South Texas that interconnects with the Raptor Gas Processing Facility. The Partnership made capital contributions to Carnero Gathering totaling $8.4 million between July 5, 2016, and September 30, 2017. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.”

In October 2016, the Partnership entered into a Purchase and Sale Agreement (the “Lease Option Purchase Agreement”) with Sanchez Energy and SN Terminal, LLC (“SNT”), pursuant to which SNT granted and conveyed to the Partnership an option to acquire a ground lease (the “Lease Option”) to which SNT is a party for a tract of land leased from the Calhoun Port Authority in Point Comfort, Texas. The Partnership, Sanchez Energy and SNT entered into an agreement terminating the Lease Option on September 11, 2017.

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 (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. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.”

In November 2016, we acquired 50% of the outstanding membership interests in Carnero Processing from SN Midstream for cash consideration of approximately $55.5 million and the assumption of approximately $24.5 million of remaining capital commitments to Carnero Processing.  The Partnership made capital contributions to Carnero Processing totaling $15.8 million between November 22, 2016 and September 30, 2017.  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 interest in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas as well as escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas for approximately $24.2 million. See further discussion of the transactions in Note 3, “Acquisitions and Divestitures.”

On September 1, 2017, we entered into an agreement with SN Catarina to transport certain quantities of SN Catarins’s natural gas on a firm basis through the SECO Pipeline for $0.22 per MMBtu delivered on or after September 1, 2017. This agreement has an initial term of one month that expired on September 30, 2017, but continues month to month thereafter unless terminated by either party.

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 Eagle Ford Shale in South Texas where it has assembled approximately 356,000 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 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, Patricio D. Sanchez and Eduardo A. Sanchez beneficially own approximately 7.4%,  3.2%,  1.1% and 1.7%, respectively, of Sanchez Energy’s shares outstanding as of September 30, 2017. Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owns approximately 15.4% of the outstanding common units of SNMP.

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Unit-Based Compensation

9 Months Ended

Sep. 30, 2017

Unit-Based Compensation

Unit-Based Compensation

13. UNIT-BASED COMPENSATION

The Sanchez Midstream Partners LP Long-Term Incentive Plan (the “LTIP”) allows for restricted common unit grants. Restricted common unit activity under the LTIP 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, 2016	219,144	$	14.22
Granted	215,814		14.83
Vested	(46,583)		15.61
Returned/Cancelled	(3,333)		13.59
Outstanding at September 30, 2017	385,042	$	14.40

In March 2017, the Partnership issued 171,231 restricted common units pursuant to the LTIP 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 LTIP 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 LTIP 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 September 30, 2017, 1,575,643 common units remain available for future issuance to participants under the LTIP.

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Distributions To Unitholders

9 Months Ended

Sep. 30, 2017

Distributions To Unitholders

Distributions To Unitholders

14. DISTRIBUTIONS TO UNITHOLDERS

The table below reflects the payment of cash distributions on common units related to the nine months ended September 30, 2017, and the previous distributions.

	Distribution		Date of	Date of	Date of
Three Months Ended	Per Unit		Declaration	Record	Distribution
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

The table below reflects the payment of distributions on Class B preferred units related to the nine months ended September 30, 2017, and the previous distributions.

	Distribution		Date of	Date of	Date of
Three Months Ended	Per Unit		Declaration	Record	Distribution
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 (b)	$	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

(a) The Partnership elected to pay the fourth quarter 2016 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.

(b) The Partnership elected to pay the 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 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017.

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Partners' Capital

9 Months Ended

Sep. 30, 2017

Partners' Capital

Partners' Capital

15. PARTNERS’ CAPITAL

Outstanding Units 

As of September 30, 2017, we had 31,000,887 Class B Preferred Units outstanding, and 14,773,192 common units outstanding.

Common Unit Issuances

In connection with providing services under the Services Agreement for the first and second quarters of 2017, the Partnership issued 139,110 and 170,497 common units, respectively, to SP Holdings, LLC on June 30, 2017 and August 31, 2017, respectively. In connection with providing services under the Services Agreement for the third and fourth quarters of 2016, the Partnership issued 170,750 and 154,737 common units, respectively, to SP Holdings, LLC on March 6, 2017. See Note 12, “Related Party Transactions” for additional information related to the Services Agreement.

The Partnership elected to pay the 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 issued 184,697 common units on May 22, 2017, to the holder of Class B preferred units.

In April 2017, we issued 84,577 common units in registered offerings for gross proceeds of approximately $1.3 million pursuant to a shelf registration statement originally filed with the SEC on March 6, 2015 as updated by that certain prospectus supplement filed with the SEC on April 6, 2017 (the “Shelf Registration Statement”). The Shelf Registration Statement allows the Partnership to sell up to $50.0 million of common units at-the-market to fund general limited partnership purposes, including possible acquisitions. Proceeds from the at-the-market equity issuance were used for general limited partnership purposes.

The Partnership elected to pay the fourth quarter 2016 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 issued 208,594 common units on February 20, 2017 to the holder of Class B preferred units.

In November 2016, we completed a public offering and private placement of common units. The public offering consisted of 6,745,107 common units (which includes partial exercise of the underwriters’ overallotment of 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses. The private placement consisted of 2,272,727 common units issued to Sanchez Energy for net proceeds of approximately $25.0 million.

In March 2016, the Partnership converted all remaining outstanding Class A Preferred Units into common units of the Partnership on a one for one basis, adjusted for the 1-for-10 unit split in August 2015.

Class B Preferred Unit Offering

On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a privately negotiated transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of approximately $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the acquisition of Western Catarina Midstream, along with the payment to Stonepeak of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units. 

Under the terms of our partnership agreement, holders of the Class B Preferred Units received 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):

	September 30,		December 31,
	2017		2016
Mezzanine equity beginning balance	$	342,991	$	172,111
Discount		—		(87)
Amortization of discount		1,300		23,477
Distributions		27,125		39,375
Distributions paid		(28,000)		(37,168)
Transfer embedded derivative to Class B		—		145,283
Total mezzanine equity	$	343,416	$	342,991

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) based on provisions of the partnership agreement, 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) as if all of the net income for the period had been distributed in accordance with the partnership agreement. 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 based on provisions of the partnership agreement. 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.

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:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Weighted Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675
Weighted Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675

At September 30, 2017, we had 385,042 common units that were restricted unvested common units granted and outstanding.  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 three months ended September 30, 2017 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(5,442)	$	(5,442)
Basic and diluted loss per unit			$	(0.38)

The following table presents our basic and diluted loss per unit for the three months ended September 30, 2016 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed income to be allocated	$	9,949	$	9,949
Basic earnings per unit			$	2.49
Assumed income to be allocated	$	28,807	$	28,807
Diluted earnings per unit			$	1.21

The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2017 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(31,754)	$	(31,754)
Basic and diluted loss per unit			$	(2.29)

The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2016 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(17,997)	$	(17,997)
Basic and diluted loss per unit			$	(5.06)

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Reporting Segments

9 Months Ended

Sep. 30, 2017

Reporting Segments

Reporting Segments

16. REPORTING SEGMENTS

“Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting 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 crude oil, natural gas and NGLs. 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 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.

The following tables set forth our segment information for the periods indicated (in thousands):

	Three Months Ended September 30, 2017
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	787	$	—	$	787
Oil sales		3,061		—		3,061
Natural gas liquids sales		514		—		514
Gathering and transportation sales		—		14,234		14,234
Total operating revenues		4,362		14,234		18,596
Operating expenses:
Lease operating expenses		1,585		150		1,735
Transportation operating expenses		—		2,661		2,661
Production taxes		340		—		340
General and administrative		4,199		1,415		5,614
Unit-based compensation expense		631		—		631
Gain on sale of assets		(2,546)		—		(2,546)
Depreciation, depletion and amortization		1,756		5,143		6,899
Accretion expense		80		69		149
Total operating expenses		6,045		9,438		15,483
Operating income (loss)	$	(1,683)	$	4,796	$	3,113

	Three Months Ended September 30, 2016
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	4,434	$	—	$	4,434
Oil sales		2,159		—		2,159
Natural gas liquids sales		264		—		264
Gathering and transportation sales		—		12,997		12,997
Total operating revenues		6,857		12,997		19,854
Operating expenses:
Lease operating expenses		2,650		117		2,767
Transportation operating expenses		—		3,111		3,111
Cost of sales		99		—		99
Production taxes		290		—		290
General and administrative		4,778		1,508		6,286
Unit-based compensation expense		90		—		90
Loss on sale of assets		219		—		219
Depreciation, depletion and amortization		2,411		5,096		7,507
Accretion expense		207		64		271
Total operating expenses		10,744		9,896		20,640
Operating income (loss)	$	(3,887)	$	3,101	$	(786)

	Nine Months Ended September 30, 2017
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	5,818	$	—	$	5,818
Oil sales		22,520		—		22,520
Natural gas liquids sales		1,473		—		1,473
Gathering and transportation sales		—		39,621		39,621
Total operating revenues		29,811		39,621		69,432
Operating expenses:
Lease operating expenses		9,957		642		10,599
Transportation operating expenses		—		8,989		8,989
Cost of sales		77		—		77
Production taxes		1,166		—		1,166
General and administrative		13,195		4,381		17,576
Unit compensation expense		1,951		—		1,951
Gain on sale of assets		(2,546)		—		(2,546)
Depreciation, depletion and amortization		7,961		20,056		28,017
Asset impairments		4,688		—		4,688
Accretion expense		444		203		647
Total operating expenses		36,893		34,271		71,164
Operating income (loss)	$	(7,082)	$	5,350	$	(1,732)

	Nine Months Ended September 30, 2016
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	8,709	$	—	$	8,709
Oil sales		4,746		—		4,746
Natural gas liquids sales		784		—		784
Gathering and transportation sales		—		41,130		41,130
Total operating revenues		14,239		41,130		55,369
Operating expenses:
Lease operating expenses		11,430		488		11,918
Transportation operating expenses		—		9,179		9,179
Cost of sales		292		—		292
Production taxes		837		—		837
General and administrative		12,762		4,221		16,983
Unit-based compensation expense		1,619		—		1,619
Loss on sale of assets		219		—		219
Depreciation, depletion and amortization		5,560		15,264		20,824
Asset impairments		1,309		—		1,309
Accretion expense		714		187		901
Total operating expenses		34,742		29,339		64,081
Operating income (loss)	$	(20,503)	$	11,791	$	(8,712)

The following table summarizes the total assets by operating segment as of September 30, 2017 and December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Segment Assets
Production	$	189,374	$	207,219
Midstream		344,310		332,486
Total assets	$	533,684	$	539,705

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Variable Interest Entities

9 Months Ended

Sep. 30, 2017

Variable Interest Entities

Variable Interest Entities

17. VARIABLE INTEREST ENTITIES

As noted above in Note 10, “Investments,” the Partnership acquired a 50% membership interest in Carnero Gathering from SN Midstream 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 variable interest entity (“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 $48.1 million.

As of September 30, 2017, the Partnership had invested approximately $45.9 million in Carnero Gathering. As of September 30, 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 10, “Investments,” the Partnership acquired a 50% membership interest in Carnero Processing from SN Midstream 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 $80.4 million.

As of September 30, 2017, the Partnership had invested approximately $71.8 million in Carnero Processing. As of September 30, 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 September 30, 2017 and December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Capital investments	$	117,699	$	107,320
Earnings in equity investments		6,800		2,301
Distributions received		(8,245)		(2,950)
Estimated earnout accrued		4,049		4,270
Equity in equity investments	$	120,303	$	110,941
	September 30,		December 31,
	2017		2016
Equity in equity investments	$	120,303	$	110,941
Guarantees of capital investments		8,247		17,584
Maximum exposure to loss	$	128,550	$	128,525

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Subsequent Events

9 Months Ended

Sep. 30, 2017

Subsequent Events

Subsequent Events

18. SUBSEQUENT EVENTS

On November 7, 2017, the board of directors of our general partner declared a third quarter 2017 cash distribution on the Partnership’s common units of $0.4508 per unit ($1.8032  per unit annualized) payable on November 30, 2017 to holders of record on November 20, 2017. The Partnership also declared a third 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 payable on November 30, 2017 to holders of record on November 20, 2017.

On November 13, 2017, we closed the Texas Production Divestiture pursuant to which we sold certain non-operated production assets located in Texas for cash consideration of approximately $6.3 million. In addition, the buyer assumed all obligations relating to the assets arising after the effective time.

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Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2017

Basis Of Presentation And Summary Of Significant Accounting Policies

Basis of Presentation

Basis of Presentation

These unaudited condensed consolidated financial statements include the accounts of SNMP and our wholly owned subsidiaries.  All intercompany accounts and transactions have been eliminated in consolidation.  We conduct our business activities as two operating segments: the production of oil and natural gas and the midstream business, which includes Western Catarina Midstream (defined below).  Our management evaluates performance based on these two business segments.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (“SEC”).  Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”), have been condensed or omitted pursuant to those rules and regulations.  We believe that the disclosures made are adequate to make the information presented not misleading.  In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included.  The results of operations for the interim periods are not necessarily indicative of the results for the entire year. 

These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of SNMP and its subsidiaries included 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.

Recent Accounting Pronouncements

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date.  Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption.

In August 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which changes the recognition and presentation requirements of hedge accounting, including eliminating the requirement to separately measure and report hedge ineffectiveness, and presenting all items that affect earnings in the same income statement line item as the hedged item.  The ASU also provides new alternatives for applying hedge accounting.  This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018.  Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements.

In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods 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 December 2016, the FASB issued ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are effective upon issuance (December 2016).

In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is effective for public business entities for annual and interim periods 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 will be effective beginning with the first quarter 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 March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. The adoption of this guidance did not have a material impact on our consolidated financial statements.

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 not early adopt the standard although early adoption is permitted. The Partnership’s expectation is to apply the modified retrospective approach. As part of the assessment, the Partnership has formed an implementation work team, completed trainings on the new revenue recognition model and gathered a representative sample of material revenue contracts covering current revenue streams for which we are currently evaluating the impact under the new standard. The Company is currently collecting all remaining contracts and evaluating the impacts to its consolidated financial statements under the revised standards. In addition, the Company is evaluating the impacts of significant historical transactions under the new standard.

Use of Estimates

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 30, 2017

Acquisitions and Divestitures

Estimated Values Of Assets Purchased And Liabilities Assumed

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

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

Fair Value Measurements

Fair Value Of Assets And Liabilities On A Recurring Basis

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 September 30, 2017 (in thousands):

	Fair Value Measurements at September 30, 2017
	Active Markets for		Observable
	Identical Assets		Inputs		Unobservable Inputs
	(Level 1)		(Level 2)		(Level 3)		Fair Value
Derivative assets (net)	$	—	$	5,263	$	—	$	5,263
Total net assets	$	—	$	5,263	$	—	$	5,263

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
Derivative assets (net)	$	—	$	6,436	$	—	$	6,436
Total net assets	$	—	$	6,436	$	—	$	6,436

Non-Recurring Fair Value Measurements Of Assets And Liabilities

The following table summarizes the non-recurring fair value measurements of our assets as of September 30, 2017 (in thousands):

	Fair Value Measurements at September 30, 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 nine months ended September 30, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas properties 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 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) During 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.

Reconciliation Of Changes In Fair Value Of Embedded Derivative Classified As Level 3

	December 31,
	2016
Beginning balance	$	(193,077)
Gain on embedded derivative		47,794
Transfer to mezzanine equity		145,283
Ending balance	$	—
Loss included in earnings related to derivatives still held as of December 31, 2016	$	—

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Derivative And Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2017

Derivative And Financial Instruments

Summary Of Derivative Contracts In Place

Fixed Price Basis Swaps–West Texas Intermediate (WTI)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price		(Bbls)	Price
2017	—	$	—	—	$	—	—	$	—	64,568	$	59.83	64,568	$	59.83
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
													758,656

Fixed Price Swaps—NYMEX (Henry Hub)

	March 31,			June 30,			September 30,			December 31,			Total
	Volume	Average		Volume	Average		Volume	Average		Volume	Average		Volume	Average
	(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price		(MMBtu)	Price
2017	—	$	—	—	$	—	—	$	—	124,160	$	3.79	124,160	$	3.79
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
													1,480,136

Schedule Of Change In Commodity Derivatives Fair Value

	September 30,		December 31,
	2017		2016
Beginning fair value of commodity derivatives	$	6,436	$	31,018
Net gains (losses) on crude oil derivatives		7,087		(8,355)
Net gains (losses) on natural gas derivatives		497		1,116
Net settlements on derivative contracts:
Crude oil		(6,133)		(13,622)
Natural gas		(2,624)		(6,919)
Net premiums on derivative contracts		—		3,198
Ending fair value of commodity derivatives	$	5,263	$	6,436

Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations

		Amount of Gain (Loss) in Income
	Location of Gain (Loss)	Three Months Ended September 30,				Nine Months Ended September 30,
Derivative Type	in Income	2017		2016		2017		2016
Commodity – Oil Hedges	Oil sales	$	(1,456)	$	(1,032)	$	7,087	$	(4,600)
Commodity – Gas Hedges	Natural gas sales		(228)		2,104		497		1,936
		$	(1,684)	$	1,072	$	7,584	$	(2,664)

Reconciliation Of Changes In Fair Value Of Embedded Derivative

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the year ended December 31, 2016 (in thousands):

	December 31,
	2016
Beginning fair value of embedded derivative	$	(193,077)
Gain on embedded derivative		47,794
Transfer to mezzanine equity		145,283
Ending fair value of embedded derivative	$	—

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Oil And Natural Gas Properties And Related Equipment (Tables)

9 Months Ended

Sep. 30, 2017

Oil And Natural Gas Properties And Related Equipment.

Gathering and Transportation Assets

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

	September 30,		December 31,
	2017		2016
Gathering and transportation assets
Midstream assets	$	183,681	$	152,209
Less: Accumulated depreciation and amortization		(24,983)		(15,020)
Total gathering and transportation assets	$	158,698	$	137,189

Oil and Natural Gas Properties

	September 30,		December 31,
	2017		2016
Gathering and transportation assets
Midstream assets	$	183,681	$	152,209
Less: Accumulated depreciation and amortization		(24,983)		(15,020)
Total gathering and transportation assets	$	158,698	$	137,189

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

	September 30,		December 31,
	2017		2016
Oil and natural gas properties and related equipment
Property costs
Proved property	$	200,422	$	758,366
Unproved property		49		46
Land		—		501
Total property costs		200,471		758,913
Materials and supplies		—		1,056
Total		200,471		759,969
Less: Accumulated depreciation, depletion, amortization and impairments		(137,420)		(674,338)
Oil and natural gas properties and equipment, net	$	63,051	$	85,631

Depreciation, Depletion, Amortization and Impairments

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2017		2016		2017		2016
Depreciation, depletion and amortization of oil and natural gas-related assets	$	1,739	$	2,348	$	7,850	$	5,310
Depreciation, depletion and amortization of gathering and transportation-related assets		1,780		1,731		9,963		5,169
Amortization of intangible assets		3,380		3,428		10,204		10,345
Total depreciation, depletion and amortization		6,899		7,507		28,017		20,824
Asset impairments		—		—		4,688		1,309
Total	$	6,899	$	7,507	$	32,705	$	22,133

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Asset Retirement Obligation (Tables)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation

Reconciliation of Asset Retirement Obligation

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

	September 30,		December 31,
	2017		2016
Asset retirement obligation, beginning balance	$	13,579	$	20,364
Liabilities added from acquisitions		198		912
Sold		(6,582)		(6,291)
Revisions to cost estimates		—		(2,399)
Settlements		(46)		(134)
Accretion expense		647		1,127
Asset retirement obligation, ending balance	$	7,796	$	13,579

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Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2017

Intangible Assets

Intangible assets

Amortization expense for the nine months ended September 30, 2017 and 2016 was $10.2 million and $10.3 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations.  Intangible assets as of September 30, 2017, and December 31, 2016 are detailed below (in thousands):

	September 30,		December 31,
	2017		2016
Beginning balance	$	185,766	$	199,741
Disposals		(32)		(219)
Amortization		(10,204)		(13,756)
Ending balance	$	175,530	$	185,766

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Investments (Tables)

9 Months Ended

Sep. 30, 2017

Investments

Summarized financial information of unconsolidated entities

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

	Nine Months Ended
	September 30,
	2017
Sales	$	57,406
Total expenses		46,734
Net income	$	10,672

	September 30,		December 31,
	2017		2016
Current assets	$	28,318	$	27,779
Noncurrent assets		190,100		152,112
Current liabilities		18,040		16,577

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Unit-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2017

Unit-Based Compensation

Schedule Of Units Activity

		Weighted
		Average
	Number of	Grant Date
	Restricted	Fair Value
	Units	Per Unit
Outstanding at December 31, 2016	219,144	$	14.22
Granted	215,814		14.83
Vested	(46,583)		15.61
Returned/Cancelled	(3,333)		13.59
Outstanding at September 30, 2017	385,042	$	14.40

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Distributions To Unitholders (Tables)

9 Months Ended

Sep. 30, 2017

Common Units

Schedule of payment of cash distributions

	Distribution		Date of	Date of	Date of
Three Months Ended	Per Unit		Declaration	Record	Distribution
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

Class B Preferred

Schedule of payment of cash distributions

	Distribution		Date of	Date of	Date of
Three Months Ended	Per Unit		Declaration	Record	Distribution
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 (b)	$	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

(a) The Partnership elected to pay the fourth quarter 2016 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.

The Partnership elected to pay the 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 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017.

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Partners' Capital (Tables)

9 Months Ended

Sep. 30, 2017

Partners' Capital

Class B Preferred Units Accounted for as Mezzanine Equity in the Consolidated Balance Sheet

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

	September 30,		December 31,
	2017		2016
Mezzanine equity beginning balance	$	342,991	$	172,111
Discount		—		(87)
Amortization of discount		1,300		23,477
Distributions		27,125		39,375
Distributions paid		(28,000)		(37,168)
Transfer embedded derivative to Class B		—		145,283
Total mezzanine equity	$	343,416	$	342,991

Schedule of Weighted Average Basic and Diluted Units Outstanding

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Weighted Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675
Weighted Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675

Loss Per Unit Amounts

The following table presents our basic and diluted loss per unit for the three months ended September 30, 2017 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(5,442)	$	(5,442)
Basic and diluted loss per unit			$	(0.38)

The following table presents our basic and diluted loss per unit for the three months ended September 30, 2016 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed income to be allocated	$	9,949	$	9,949
Basic earnings per unit			$	2.49
Assumed income to be allocated	$	28,807	$	28,807
Diluted earnings per unit			$	1.21

The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2017 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(31,754)	$	(31,754)
Basic and diluted loss per unit			$	(2.29)

The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2016 (in thousands, except for per unit amounts):

	Total		Common Units
Assumed net loss to be allocated	$	(17,997)	$	(17,997)
Basic and diluted loss per unit			$	(5.06)

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Reporting Segments (Tables)

9 Months Ended

Sep. 30, 2017

Reporting Segments

Schedule of Segment Information

The following tables set forth our segment information for the periods indicated (in thousands):

	Three Months Ended September 30, 2017
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	787	$	—	$	787
Oil sales		3,061		—		3,061
Natural gas liquids sales		514		—		514
Gathering and transportation sales		—		14,234		14,234
Total operating revenues		4,362		14,234		18,596
Operating expenses:
Lease operating expenses		1,585		150		1,735
Transportation operating expenses		—		2,661		2,661
Production taxes		340		—		340
General and administrative		4,199		1,415		5,614
Unit-based compensation expense		631		—		631
Gain on sale of assets		(2,546)		—		(2,546)
Depreciation, depletion and amortization		1,756		5,143		6,899
Accretion expense		80		69		149
Total operating expenses		6,045		9,438		15,483
Operating income (loss)	$	(1,683)	$	4,796	$	3,113

	Three Months Ended September 30, 2016
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	4,434	$	—	$	4,434
Oil sales		2,159		—		2,159
Natural gas liquids sales		264		—		264
Gathering and transportation sales		—		12,997		12,997
Total operating revenues		6,857		12,997		19,854
Operating expenses:
Lease operating expenses		2,650		117		2,767
Transportation operating expenses		—		3,111		3,111
Cost of sales		99		—		99
Production taxes		290		—		290
General and administrative		4,778		1,508		6,286
Unit-based compensation expense		90		—		90
Loss on sale of assets		219		—		219
Depreciation, depletion and amortization		2,411		5,096		7,507
Accretion expense		207		64		271
Total operating expenses		10,744		9,896		20,640
Operating income (loss)	$	(3,887)	$	3,101	$	(786)

	Nine Months Ended September 30, 2017
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	5,818	$	—	$	5,818
Oil sales		22,520		—		22,520
Natural gas liquids sales		1,473		—		1,473
Gathering and transportation sales		—		39,621		39,621
Total operating revenues		29,811		39,621		69,432
Operating expenses:
Lease operating expenses		9,957		642		10,599
Transportation operating expenses		—		8,989		8,989
Cost of sales		77		—		77
Production taxes		1,166		—		1,166
General and administrative		13,195		4,381		17,576
Unit compensation expense		1,951		—		1,951
Gain on sale of assets		(2,546)		—		(2,546)
Depreciation, depletion and amortization		7,961		20,056		28,017
Asset impairments		4,688		—		4,688
Accretion expense		444		203		647
Total operating expenses		36,893		34,271		71,164
Operating income (loss)	$	(7,082)	$	5,350	$	(1,732)

	Nine Months Ended September 30, 2016
	Production		Midstream		Total
Operating revenues
Natural gas sales	$	8,709	$	—	$	8,709
Oil sales		4,746		—		4,746
Natural gas liquids sales		784		—		784
Gathering and transportation sales		—		41,130		41,130
Total operating revenues		14,239		41,130		55,369
Operating expenses:
Lease operating expenses		11,430		488		11,918
Transportation operating expenses		—		9,179		9,179
Cost of sales		292		—		292
Production taxes		837		—		837
General and administrative		12,762		4,221		16,983
Unit-based compensation expense		1,619		—		1,619
Loss on sale of assets		219		—		219
Depreciation, depletion and amortization		5,560		15,264		20,824
Asset impairments		1,309		—		1,309
Accretion expense		714		187		901
Total operating expenses		34,742		29,339		64,081
Operating income (loss)	$	(20,503)	$	11,791	$	(8,712)

Summary of Total Assets by Operating Segment

The following table summarizes the total assets by operating segment as of September 30, 2017 and December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Segment Assets
Production	$	189,374	$	207,219
Midstream		344,310		332,486
Total assets	$	533,684	$	539,705

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2017

Variable Interest Entities

Schedule of Carrying Amounts of Assets and Liabilities of Variable Interest Entity

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 September 30, 2017 and December 31, 2016 (in thousands):

	September 30,		December 31,
	2017		2016
Capital investments	$	117,699	$	107,320
Earnings in equity investments		6,800		2,301
Distributions received		(8,245)		(2,950)
Estimated earnout accrued		4,049		4,270
Equity in equity investments	$	120,303	$	110,941
	September 30,		December 31,
	2017		2016
Equity in equity investments	$	120,303	$	110,941
Guarantees of capital investments		8,247		17,584
Maximum exposure to loss	$	128,550	$	128,525

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Organization And Business (Details) $ in Thousands				1 Months Ended			9 Months Ended
	Nov. 13, 2017 USD ($)	May 10, 2017 USD ($)	Jul. 05, 2016	Aug. 31, 2017 MMcf	Jul. 31, 2017 USD ($)	Nov. 30, 2016 USD ($) item shares	Sep. 30, 2017 USD ($) shares	Dec. 31, 2016 shares
Units, issued | shares							14,773,192	13,447,749
Proceeds from common units sold							$ 1,290
Daily pipeline capacity (MMcf/d) | MMcf				400
IPO
Units, issued | shares						6,745,107
Proceeds from common units sold						$ 69,700
Private Placement
Units, issued | shares						2,272,727
Proceeds from common units sold						$ 25,000
Over-Allotment Option
Units, issued | shares						194,305
Carnero Gathering LLC, Joint Venture
Gathering and processing agreement term			15 years
Ownership interest (as a percent)			50.00%
Sanchez Energy
Gathering and processing agreement term							15 years
Sanchez Energy | Acquisition of Wellbore Interests
Producing wellbores | item						23
Sanchez Energy | Acquisition of Working Interests
Producing wellbores | item						11
Oklahoma Production Divestiture
Proceeds from divestiture of business		$ 5,500			$ 5,500
Oklahoma Production Divestiture | Subsequent event
Proceeds from divestiture of business	$ 6,300

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Basis Of Presentation And Summary Of Significant Accounting Policies (Details)	9 Months Ended
	Sep. 30, 2017 segment
Basis Of Presentation And Summary Of Significant Accounting Policies
Number of operating segments	2

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Acquisitions and Divestitures (Details)									1 Months Ended		9 Months Ended	15 Months Ended	24 Months Ended
	Nov. 13, 2017 USD ($)	Oct. 12, 2017 USD ($)	Jul. 17, 2017 USD ($)	May 10, 2017 USD ($)	Nov. 30, 2016 USD ($)	Nov. 22, 2016 USD ($) item	Jul. 05, 2016 USD ($)	Jun. 15, 2016 USD ($)	Jul. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)
Carnero Processing Acquisition
Business Acquisition [Line Items]
Acquisition membership interest (as percent)						50.00%
Cash payment for acquisition						$ 55,500,000
Capital contribution commitments						24,500,000
Payments to acquire interest in joint venture					$ 15,800,000					$ 15,800,000	$ 15,800,000
Eagle Ford
Business Acquisition [Line Items]
Purchase price						$ 25,016,000
Carnero Gathering LLC, Joint Venture
Business Acquisition [Line Items]
Ownership interest (as a percent)							50.00%
Payments to acquire interest in joint venture							$ 37,000,000				$ 5,100,000	$ 8,400,000	$ 8,400,000
Assumption of capital commitments in joint venture							$ 7,400,000
TPL South Tex Processing Company LP
Business Acquisition [Line Items]
Ownership interest (as a percent)						50.00%	50.00%
SN Cotulla Assets, LLC and SN Palmetto, LLC
Business Acquisition [Line Items]
Producing wellbores | item						23
SN Cotulla Assets, LLC and SN Palmetto, LLC | Eagle Ford
Business Acquisition [Line Items]
Cash payment for acquisition						$ 24,200,000
Producing wellbores | item						11
Closing adjustments						$ 2,800,000
Texas Production Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture of business		$ 6,300,000
Oklahoma Production Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture of business				$ 5,500,000					$ 5,500,000
Gain on sale			$ 2,400,000
Oklahoma Production Divestiture | Subsequent event
Business Acquisition [Line Items]
Proceeds from divestiture of business	$ 6,300,000
Gateway Resources U.S.A., Inc.
Business Acquisition [Line Items]
Loss on disposition of intangible assets								$ 200,000
Gateway Resources U.S.A., Inc. | Mid-Continent Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture of business								$ 7,120

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Acquisitions and Divestitures (Value Net Assets Acquired) (Details) - Eagle Ford $ in Thousands	Nov. 22, 2016 USD ($)
Business Acquisition [Line Items]
Proved developed reserves	$ 25,016
Fair value of assets acquired	25,016
Asset retirement obligations	(832)
Fair value of net assets acquired	$ 24,184

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Fair Value Measurements (Recurring) (Details) $ in Thousands	Sep. 30, 2017 USD ($) derivative	Dec. 31, 2016 USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Number of interest rate derivatives | derivative	0
Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total net assets	$ 5,263	$ 6,436
Fair value of derivative instruments	5,263	6,436
Fair Value, Inputs, Level 2 | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets (net)	5,263	6,436
Total net assets	$ 5,263	$ 6,436

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Fair Value Measurements (Non-Recurring) (Details) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments	$ 4,688	$ 1,309	$ 7,600
Fair Value, Inputs, Level 3 | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	7,277		10,733
Acquisitions			24,184
Total net assets	$ 7,277		$ 34,917

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Fair Value Measurements (Embedded Derivative) (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Fair Value Measurements
Beginning Balance		$ (193,077)
Gain on embedded derivative		47,794
Transfer to mezzanine equity		145,283
Ending Balance
(Loss) on embedded derivative

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Derivative And Financial Instruments (Hedges In Place) (Details)	9 Months Ended
	Sep. 30, 2017 MMBTU $ / bbl $ / MMBTU bbl
West Texas Intermediate 2017 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	64,568
Average Price | $ / bbl	59.83
West Texas Intermediate 2017
Derivative [Line Items]
Volume (in Bbls) | bbl	64,568
Average Price | $ / bbl	59.83
West Texas Intermediate 2018 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	70,600
Average Price | $ / bbl	59.63
West Texas Intermediate 2018 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	66,432
Average Price | $ / bbl	59.71
West Texas Intermediate 2018 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	62,840
Average Price | $ / bbl	59.78
West Texas Intermediate 2018 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	59,704
Average Price | $ / bbl	59.84
West Texas Intermediate 2018
Derivative [Line Items]
Volume (in Bbls) | bbl	259,576
Average Price | $ / bbl	59.74
West Texas Intermediate 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	62,528
Average Price | $ / bbl	60.41
West Texas Intermediate 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	59,552
Average Price | $ / bbl	60.44
West Texas Intermediate 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	57,024
Average Price | $ / bbl	60.48
West Texas Intermediate 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	54,824
Average Price | $ / bbl	60.52
West Texas Intermediate 2019
Derivative [Line Items]
Volume (in Bbls) | bbl	233,928
Average Price | $ / bbl	60.46
West Texas Intermediate 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	52,776
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	50,960
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	49,224
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	47,624
Average Price | $ / bbl	53.50
West Texas Intermediate 2020
Derivative [Line Items]
Volume (in Bbls) | bbl	200,584
Average Price | $ / bbl	53.50
West Texas Intermediate
Derivative [Line Items]
Volume (in Bbls) | bbl	758,656
NYMEX 2017 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	124,160
Average Price | $ / MMBTU	3.79
NYMEX 2017
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	124,160
Average Price | $ / MMBTU	3.79
NYMEX 2018 Swap Quarter
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	132,088
Average Price | $ / MMBTU	3.00
NYMEX 2018 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	126,600
Average Price | $ / MMBTU	3.00
NYMEX 2018 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	121,600
Average Price | $ / MMBTU	3.00
NYMEX 2018 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	117,040
Average Price | $ / MMBTU	3.00
NYMEX 2018
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	497,328
Average Price | $ / MMBTU	3.00
NYMEX 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	119,832
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	115,784
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	112,032
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	108,552
Average Price | $ / MMBTU	2.85
NYMEX 2019
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	456,200
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	105,104
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	102,008
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	99,136
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	96,200
Average Price | $ / MMBTU	2.85
NYMEX 2020
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	402,448
Average Price | $ / MMBTU	2.85
NYMEX
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,480,136

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Derivative And Financial Instruments (Changes In Fair Value) (Details) $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Aug. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($) item	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		$ (1,684)	$ 1,072	$ 7,584	$ (2,664)
Early termination of hedges	$ 3,600
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives				6,436	31,018	$ 31,018
Net premiums on derivative contracts						3,198
Ending fair value of commodity derivatives		5,263		$ 5,263		6,436
Number of counterparties | item				4
Oil | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives				$ 7,087		(8,355)
Net settlements on derivative contracts				(6,133)		(13,622)
Oil | Oil And Liquids Sales | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		(1,456)	(1,032)	7,087	(4,600)
Natural Gas | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives				497		1,116
Net settlements on derivative contracts				(2,624)		$ (6,919)
Natural Gas | Natural Gas Sales | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		$ (228)	$ 2,104	$ 497	$ 1,936

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Derivative And Financial Instruments (Embedded Derivative) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Dec. 31, 2016
Derivative And Financial Instruments
Beginning Balance		$ (193,077)	$ (193,077)
Gain on embedded derivative	$ 30,012	$ 43,204	47,794
Transfer to mezzanine equity			145,283
Ending Balance

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Long-Term Debt (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)	May 19, 2016 USD ($)
Line of Credit Facility [Line Items]
Amortization of debt issuance costs	$ 100	$ 100	$ 391	$ 377
Unamortized debt issue costs	1,300		1,300		$ 1,700
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	215,600		215,600
Sub-limit which may be used for issuance of letters of credit	15,000		$ 15,000
Borrowing base amount						$ 200,000
Commitment fee on unutilized borrowing base			0.50%
Credit Agreement | Second full quarter after Catarina acquisition
Line of Credit Facility [Line Items]
Borrowing base multiplier			4.5
Credit Facility Maturing March 31, 2020
Line of Credit Facility [Line Items]
Maximum borrowing capacity	500,000		$ 500,000
lender loan
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 200,000		$ 200,000
Minimum | Credit Agreement
Line of Credit Facility [Line Items]
Consolidated current asset ratio			1.0
Required interest coverage ratio			2.5
Distribution limitation, credit facility excess over borrowing base (as a percent)			90.00%
Ownership percentage by subsidiary			50
Minimum | Credit Agreement | Scenario One
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5		4.5
Minimum | Credit Agreement | Scenario Two
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.0		4.0
Minimum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate			2.25%
Minimum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate			1.25%
Maximum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate			3.25%
Maximum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate			2.25%

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Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Midstream assets	$ 183,681	$ 152,209
Less: Accumulated depreciation and amortization	(137,420)	(674,338)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	183,681	152,209
Less: Accumulated depreciation and amortization	(24,983)	(15,020)
Total gathering and transportation assets	$ 158,698	$ 137,189

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Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 200,422	$ 758,366
Unproved property	49	46
Land		501
Total property costs	200,471	758,913
Materials and supplies		1,056
Total	200,471	759,969
Less: Accumulated depreciation, depletion, amortization and impairments	(137,420)	(674,338)
Oil and natural gas properties and equipment, net	$ 63,051	$ 85,631

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Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Amortization of intangible assets			$ 10,204	$ 10,345
Depreciation, depletion and amortization			17,813	11,341
Asset impairments			4,688	1,309
Total	$ 6,899	$ 7,507	32,705	22,133
Non-cash impairment charges	0	0	4,700	1,300
Proved property	200,422		200,422		$ 758,366
Exploration and dry hole costs			$ 0	0
Gathering Facilities
Property, Plant and Equipment [Line Items]
Useful lives			36 years
Oil and Natural Gas-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	1,739	2,348	$ 7,850	5,310
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	1,780	1,731	$ 9,963	5,169
Gathering and Transportation Related Assets | Minimum
Property, Plant and Equipment [Line Items]
Useful lives			3 years
Gathering and Transportation Related Assets | Maximum
Property, Plant and Equipment [Line Items]
Useful lives			15 years
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	3,380	3,428	$ 10,204	10,345
Depreciation, depletion and amortization	$ 6,899	$ 7,507	$ 28,017	$ 20,824

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Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Asset Retirement Obligation
Asset retirement obligation, beginning balance			$ 13,579	$ 20,364	$ 20,364
Liabilities added from acquisitions			198		912
Sold			(6,582)		(6,291)
Revisions to cost estimates					(2,399)
Settlements			(46)		(134)
Accretion expense	$ 149	$ 271	647	$ 901	1,127
Asset retirement obligation, ending balance	7,796		7,796		13,579
Legally restricted assets	$ 0		$ 0		$ 0

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Intangible Assets (Details) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2017 USD ($) a	Sep. 30, 2016 USD ($)	Dec. 31, 2016 USD ($)
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 10,204	$ 10,345
Beginning balance	185,766	$ 199,741	$ 199,741
Disposals	(32)		(219)
Amortization	(10,204)		(13,756)
Ending balance	$ 175,530		185,766
Customer Contracts
Finite-Lived Intangible Assets [Line Items]
Agreement term	15 years
Dedicated acreage | a	35,000
Useful life	15 years
Ending balance	$ 175,500
Marketing Contracts
Finite-Lived Intangible Assets [Line Items]
Amortization			$ 200

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Investments (Details) - USD ($) $ in Thousands			3 Months Ended		7 Months Ended	9 Months Ended		15 Months Ended	24 Months Ended
	Nov. 22, 2016	Jul. 05, 2016	Sep. 30, 2017	Sep. 30, 2016	Jun. 30, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016	Nov. 30, 2016	Jun. 05, 2016
Schedule of Equity Method Investments [Line Items]
Capital investments			$ 117,699			$ 117,699		$ 117,699		$ 107,320
Earnout			4,049			4,049		4,049		$ 4,270
Earnings in equity investments			2,873	$ 1,124		4,397	$ 1,136
Amortization of intangible assets						10,204	10,345
Cash distributions						18,530	$ 4,815
Carnero Gathering LLC, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		50.00%
Payments to acquire interest in joint venture		$ 37,000				5,100		8,400	$ 8,400
Assumption of capital commitments in joint venture		$ 7,400
Capital investments			45,900			45,900		45,900
Agreement term		15 years
Earnings in equity investments			2,000			4,700
Cash distributions						5,300
Carnero Gathering LLC, Joint Venture | Customer Relationships
Schedule of Equity Method Investments [Line Items]
Intangible asset, fair value		$ 13,000
Amortization of intangible assets			200			600
Carnero Processing Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%										50.00%
Payments to acquire interest in joint venture	$ 55,500				$ 15,800
Assumption of capital commitments in joint venture	24,500
Payments of capital commitments from joint venture						5,300
Capital investments	$ 48,000		71,800			71,800		$ 71,800
Earnings in equity investments			1,000			500
TPL South Tex Processing Company LP
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%	50.00%
SN Midstream | Carnero Gathering LLC, Joint Venture
Schedule of Equity Method Investments [Line Items]
Capital investments												$ 26,000
Earnout payments			$ 0			$ 0

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Investments (Summarized Financial Information of Unconsolidated Entities) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Investments
Sales	$ 57,406
Total expenses	46,734
Net income	10,672
Current assets	28,318	$ 27,779
Noncurrent assets	190,100	152,112
Current liabilities	$ 18,040	$ 16,577

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Commitments And Contingencies (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Commitments And Contingencies
Estimated earnout accrued	$ 4,049	$ 4,270

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Related Party Transactions (Details) $ in Millions				1 Months Ended	7 Months Ended	9 Months Ended	15 Months Ended	24 Months Ended
	Nov. 22, 2016 USD ($)	Jul. 05, 2016 USD ($)	Oct. 14, 2015 a Mcf bbl	Nov. 30, 2016 USD ($) item shares	Jun. 30, 2017 USD ($)	Sep. 30, 2017 USD ($) a $ / MMBTU	Sep. 30, 2017 USD ($) a	Jun. 30, 2017 USD ($)	Dec. 31, 2016 USD ($)
Related Party Transaction [Line Items]
Related parties, net receivable						$ 6.7	$ 6.7		$ 6.0
Related parties, net payable						$ 6.5	$ 6.5		$ 7.0
Ownership by related parties (as a percentage)						15.40%	15.40%
Sanchez Energy
Related Party Transaction [Line Items]
Agreement term						15 years
Payments to acquire interest in joint venture				$ 25.0
Assumption of capital commitments in joint venture				$ 24.2
Net acres assembled | a						356,000	356,000
SP Holdings
Related Party Transaction [Line Items]
Percent of value of properties held used to compute quarterly fee						0.375%	0.375%
Maximum asset acquisition, disposition and financing fee (as a percent)						2.00%
Agreement term						10 years
Services Agreement renewal term						1 year
Agreement notice period						180 days
Administrative fee paid						$ 6.5
Seco Pipeline, LLC
Related Party Transaction [Line Items]
Agreement for transported natural gas quantities to SN Catarina (price per unit) | $ / MMBTU						0.22
Perpetual term of agreement unless terminated						1 month
Carnero Processing Joint Venture
Related Party Transaction [Line Items]
Ownership interest (as a percent)	50.00%			50.00%
Payments to acquire interest in joint venture	$ 55.5				$ 15.8
Assumption of capital commitments in joint venture	$ 24.5
Carnero Processing Joint Venture | Sanchez Energy
Related Party Transaction [Line Items]
Payments to acquire interest in joint venture				$ 55.5
Assumption of capital commitments in joint venture				$ 24.5
Carnero Gathering LLC, Joint Venture
Related Party Transaction [Line Items]
Agreement term		15 years
Ownership interest (as a percent)		50.00%
Payments to acquire interest in joint venture		$ 37.0				$ 5.1	$ 8.4	$ 8.4
Assumption of capital commitments in joint venture		$ 7.4
TPL South Tex Processing Company LP
Related Party Transaction [Line Items]
Ownership interest (as a percent)	50.00%	50.00%
Acquisition of Wellbore Interests | Sanchez Energy
Related Party Transaction [Line Items]
Producing wellbores | item				23
Acquisition of Working Interests | Sanchez Energy
Related Party Transaction [Line Items]
Producing wellbores | item				11
Western Catarina Midstream
Related Party Transaction [Line Items]
Agreement term			15 years
Acres dedicated for gathering | a			35,000
Gathering Agreement delivery commitment period			5 years
Western Catarina Midstream | Oil
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | bbl			10,200
Western Catarina Midstream | Natural Gas
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | Mcf			142,000
Common Units | Sanchez Energy
Related Party Transaction [Line Items]
Shares repurchased | shares				2,272,727
Common Units | Sanchez Energy | Executive Chairman
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						7.40%	7.40%
Common Units | Sanchez Energy | Chief Executive Officer
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						3.20%	3.20%
Common Units | Sanchez Energy | Vice President
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						1.10%	1.10%
Common Units | Sanchez Energy | President
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						1.70%	1.70%

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Unit-Based Compensation (Restricted Units Activity) (Details) - $ / shares	1 Months Ended		9 Months Ended	12 Months Ended
	Apr. 30, 2017	Mar. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			385,042
LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units available for issuance			1,575,643
Restricted Stock Units (RSUs) | LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			219,144
Number of Restricted Units, Granted	44,583	171,231	215,814
Number of Restricted Units, Vested			(46,583)
Number of Restricted Units, Returned/Cancelled			(3,333)
Number of Restricted Units, Outstanding			385,042	219,144
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 14.22
Weighted Averaged Grant Date Fair Value Per Unit, Granted			14.83
Weighted Averaged Grant Date Fair Value Per Unit, Vested			15.61
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled			13.59
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 14.40	$ 14.22
Prior To Stock Split | Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted				67,627

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Distributions To Unitholders (Details) - $ / shares			3 Months Ended					9 Months Ended
	May 31, 2017	Feb. 28, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Sep. 30, 2017
Common Units
Distribution paid per unit			$ 0.4508	$ 0.4441	$ 0.4375	$ 0.4310	$ 0.4246
Aggregate distribution of units								393,291
Class B Preferred
Distribution paid per unit			$ 0.28225	$ 0.28225	$ 0.2258	$ 0.2258	$ 0.4500
Aggregate distribution of units	184,697	208,594

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Partners' Capital (Details) $ / shares in Units, $ in Thousands					1 Months Ended			3 Months Ended					9 Months Ended
	May 22, 2017 shares	Feb. 20, 2017 shares	Jan. 25, 2017 $ / shares shares	Oct. 14, 2015 USD ($) $ / shares shares	Apr. 30, 2017 USD ($) shares	Nov. 30, 2016 USD ($) shares	Aug. 31, 2015	Jun. 30, 2017 shares	Mar. 31, 2017 shares	Dec. 31, 2016 shares	Sep. 30, 2016 shares	Dec. 31, 2015	Sep. 30, 2017 USD ($) shares	Dec. 06, 2016 shares	Mar. 31, 2016
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding										29,296,441			31,000,887
Units, outstanding										13,447,749			14,773,192
Class A preferred units converted to common shares, conversion ratio															1
Units, issued										13,447,749			14,773,192
Proceeds from common units sold | $													$ 1,290
Class B preferred units, issued										29,296,441			31,000,887
IPO
Limited Partners' Capital Account [Line Items]
Units, issued						6,745,107
Proceeds from common units sold | $						$ 69,700
Private Placement
Limited Partners' Capital Account [Line Items]
Units, issued						2,272,727
Proceeds from common units sold | $						$ 25,000
Over-Allotment Option
Limited Partners' Capital Account [Line Items]
Units, issued						194,305
Class A Preferred Units
Limited Partners' Capital Account [Line Items]
Reverse stock split ratio							0.10
Class B Preferred
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding													31,000,887
Units, issued														9,851,996
Units sold (in units)	184,697	208,594		19,444,445
Price per unit sold | $ / shares				$ 18.00
Proceeds from preferred units sold | $				$ 350,000
Percent of consideration paid				2.25%
Paid in full in cash, per annum												10.00%
Paid in part cash, per annum												12.00%
Dividend per annum												8.00%
Paid-in kind per annum												4.00%
Class B Preferred | Settlement Agreement with Stonepeak Catarina Holdings LLC
Limited Partners' Capital Account [Line Items]
Class B preferred units, issued			1,704,446
Class B preferred units, unit price | $ / shares			$ 11.29
Common Units
Limited Partners' Capital Account [Line Items]
Units, outstanding													14,773,192
Units, issued					84,577
Units sold (in units)								170,497	139,110	154,737	170,750
Proceeds from common units sold | $					$ 1,300
Common units authorized for sale, value | $					$ 50,000
Minimum | Class B Preferred
Limited Partners' Capital Account [Line Items]
Preferred unit conversion, amount | $													$ 17,500

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Partners Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Mezzanine equity beginning balance	$ 342,991
Distributions	22,750	$ 24,918
Total mezzanine equity	343,416		$ 342,991
Class B Preferred
Mezzanine equity beginning balance	342,991	$ 172,111	172,111
Discount			(87)
Amortization of discount	1,300		23,477
Distributions	27,125		39,375
Distributions paid	(28,000)		(37,168)
Transfer embedded derivative to Class B			145,283
Total mezzanine equity	$ 343,416		$ 342,991

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Partners' Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Weighted Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Weighted Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675
Restricted unvested common units granted and outstanding	385,042		385,042
Assumed net income (loss) to be allocated	$ (5,442)	$ 9,949	$ (31,754)	$ (17,997)
Assumed income to be allocated		$ 28,807
Basic earnings per unit	$ (0.38)	$ 2.49	$ (2.29)	$ (5.06)
Diluted earnings per unit	$ (0.38)	$ 1.21	$ (2.29)	$ (5.06)
Asset impairments			$ 4,688	$ 1,309
Common Units
Weighted Common units - Basic	14,313,999	3,998,209	13,888,057	3,556,675
Weighted Common units - Diluted	14,313,999	23,771,370	13,888,057	3,556,675
Assumed net income (loss) to be allocated	$ (5,442)	$ 9,949	$ (31,754)	$ (17,997)
Assumed income to be allocated		$ 28,807
Net loss per unit - Basic and diluted	$ (0.38)	$ 1.21	$ (2.29)	$ (5.06)
Basic earnings per unit		$ 2.49
Restricted Unvested Units
Assumed net income (loss) to be allocated			$ 0

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Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Operating Revenues
Natural gas sales	$ 787	$ 4,434	$ 5,818	$ 8,709
Oil sales	3,061	2,159	22,520	4,746
Natural gas liquids sales	514	264	1,473	784
Gathering and transportation sales	14,234	12,997	39,621	41,130
Total revenues	18,596	19,854	69,432	55,369
Operating expenses:
Lease operating expenses	1,735	2,767	10,599	11,918
Transportation operating expenses	2,661	3,111	8,989	9,179
Cost of sales		99	77	292
Production taxes	340	290	1,166	837
General and administrative	5,614	6,286	17,576	16,983
Unit-based compensation expense	631	90	1,951	1,619
Loss (gain) on sale of assets	(2,546)	219	(2,546)	219
Depreciation, depletion and amortization	6,899	7,507	28,017	20,824
Asset impairments			4,688	1,309
Accretion expense	149	271	647	901	$ 1,127
Total operating expenses	15,483	20,640	71,164	64,081
Operating income (loss)	3,113	(786)	(1,732)	(8,712)
Upstream
Operating Revenues
Natural gas sales	787	4,434	5,818	8,709
Oil sales	3,061	2,159	22,520	4,746
Natural gas liquids sales	514	264	1,473	784
Total revenues	4,362	6,857	29,811	14,239
Operating expenses:
Lease operating expenses	1,585	2,650	9,957	11,430
Cost of sales		99	77	292
Production taxes	340	290	1,166	837
General and administrative	4,199	4,778	13,195	12,762
Unit-based compensation expense	631	90	1,951	1,619
Loss (gain) on sale of assets	(2,546)	219	(2,546)	219
Depreciation, depletion and amortization	1,756	2,411	7,961	5,560
Asset impairments			4,688	1,309
Accretion expense	80	207	444	714
Total operating expenses	6,045	10,744	36,893	34,742
Operating income (loss)	(1,683)	(3,887)	(7,082)	(20,503)
Midstream
Operating Revenues
Gathering and transportation sales	14,234	12,997	39,621	41,130
Total revenues	14,234	12,997	39,621	41,130
Operating expenses:
Lease operating expenses	150	117	642	488
Transportation operating expenses	2,661	3,111	8,989	9,179
General and administrative	1,415	1,508	4,381	4,221
Depreciation, depletion and amortization	5,143	5,096	20,056	15,264
Accretion expense	69	64	203	187
Total operating expenses	9,438	9,896	34,271	29,339
Operating income (loss)	$ 4,796	$ 3,101	$ 5,350	$ 11,791

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Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 533,684	$ 539,705
Upstream
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	189,374	207,219
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 344,310	$ 332,486

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Variable Interest Entities (Details) - USD ($) $ in Thousands			7 Months Ended	9 Months Ended	12 Months Ended	15 Months Ended	24 Months Ended
	Nov. 22, 2016	Jul. 05, 2016	Jun. 30, 2017	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2017	Jun. 30, 2017	Nov. 30, 2016
Variable Interest Entity [Line Items]
Capital investments				$ 117,699	$ 107,320	$ 117,699
Earnings in equity investments				6,800	2,301	6,800
Distributions received				(8,245)	(2,950)
Estimated earnout accrued				4,049	4,270	4,049
Equity in equity investments				120,303	110,941	120,303
Guarantees of capital investments				8,247	17,584	8,247
Maximum exposure to loss				128,550	$ 128,525	128,550
Carnero Processing Joint Venture
Variable Interest Entity [Line Items]
Ownership interest (as a percent)	50.00%							50.00%
Payments to acquire interest in joint venture	$ 55,500		$ 15,800
Assumption of capital commitments in joint venture	24,500
Debt incurred				0		0
Capital investments	$ 48,000			71,800		71,800
Maximum exposure to loss				80,400		80,400
Carnero Gathering LLC, Joint Venture
Variable Interest Entity [Line Items]
Ownership interest (as a percent)		50.00%
Payments to acquire interest in joint venture		$ 37,000		5,100		8,400	$ 8,400
Assumption of capital commitments in joint venture		$ 7,400
Debt incurred				0		0
Capital investments				45,900		45,900
Maximum exposure to loss				$ 48,100		$ 48,100

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Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions								1 Months Ended	9 Months Ended
	Nov. 30, 2017	Nov. 13, 2017	Nov. 07, 2017	Oct. 12, 2017	May 31, 2017	May 10, 2017	Feb. 28, 2017	Jul. 31, 2017	Sep. 30, 2017
Credit Agreement
Subsequent Event [Line Items]
Maximum borrowing capacity									$ 215.6
lender loan
Subsequent Event [Line Items]
Maximum borrowing capacity									$ 200.0
Common Units
Subsequent Event [Line Items]
Aggregate distribution of units									393,291
Class B Preferred
Subsequent Event [Line Items]
Aggregate distribution of units					184,697		208,594
Subsequent event | Common Units
Subsequent Event [Line Items]
Distribution declared per unit			$ 0.4508
Annual distribution declared per unit			$ 1.8032
Subsequent event | Class B Preferred
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.28225
Oklahoma Production Divestiture
Subsequent Event [Line Items]
Proceeds from divestiture of business						$ 5.5		$ 5.5
Oklahoma Production Divestiture | Subsequent event
Subsequent Event [Line Items]
Proceeds from divestiture of business		$ 6.3
Texas Production Divestiture
Subsequent Event [Line Items]
Proceeds from divestiture of business				$ 6.3