Evolve Transition Infrastructure (SNMP) 10-Q 14 Nov 17 2017 Q3 Quarterly report Financial data

Document and Entity Information

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	2,017
Document Fiscal Period Focus	Q3
Entity Registrant Name	Sanchez Midstream Partners LP
Entity Central Index Key	1,362,705
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

Condensed Consolidated Statemen

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

Condensed Consolidated Balance

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

Condensed Consolidated Balance4

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

Condensed Consolidated Stateme5

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

Condensed Consolidated Stateme6

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

Condensed Consolidated Stateme7

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

Organization And Business

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.

Basis Of Presentation And Summa

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.

Acquisitions and Divestitures

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 .

Fair Value Measurements

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 Dec ember 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 $ —

Derivative And Financial Instru

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 $ —

Long-Term Debt

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.

Oil And Natural Gas Properties

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.

Asset Retirement Obligation

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.

Intangible Assets

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

Investments

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

Commitments And Contingencies

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.

Related Party Transactions

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.

Unit-Based Compensation

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.

Distributions To Unitholders

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.

Partners' Capital

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)

Reporting Segments

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

Variable Interest Entities

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

Subsequent Events

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.

Basis Of Presentation And Sum26

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.

Acquisitions and Divestitures (

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

Fair Value Measurements (Tables

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 $ —

Derivative And Financial Inst29

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 $ —

Oil And Natural Gas Propertie30

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

Asset Retirement Obligation (Ta

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

Intangible Assets (Tables)

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

Investments (Tables)

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

Unit-Based Compensation (Tables

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

Distributions To Unitholders (T

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.

Partners' Capital (Tables)

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)

Reporting Segments (Tables)

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

Variable Interest Entities (Tab

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

Organization And Business (Deta

Organization And Business (Details) $ in Thousands	Nov. 13, 2017USD ($)	May 10, 2017USD ($)	Jul. 05, 2016	Aug. 31, 2017MMcf	Jul. 31, 2017USD ($)	Nov. 30, 2016USD ($)itemshares	Sep. 30, 2017USD ($)shares	Dec. 31, 2016shares
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

Basis Of Presentation And Sum40

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

Acquisitions and Divestitures41

Acquisitions and Divestitures (Details)

Nov. 13, 2017USD ($)

Oct. 12, 2017USD ($)

Jul. 17, 2017USD ($)

May 10, 2017USD ($)

Nov. 30, 2016USD ($)

Nov. 22, 2016USD ($)item

Jul. 05, 2016USD ($)

Jun. 15, 2016USD ($)

Jul. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Sep. 30, 2017USD ($)

Sep. 30, 2017USD ($)

Jun. 30, 2017USD ($)

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

Acquisitions and Divestitures42

Acquisitions and Divestitures (Value Net Assets Acquired) (Details) - Eagle Ford $ in Thousands	Nov. 22, 2016USD ($)
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

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) $ in Thousands	Sep. 30, 2017USD ($)derivative	Dec. 31, 2016USD ($)
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

Fair Value Measurements (Non-Re

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

Fair Value Measurements (Embedd

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

Derivative And Financial Inst46

Derivative And Financial Instruments (Hedges In Place) (Details)	9 Months Ended
	Sep. 30, 2017MMBTU$ / bbl$ / MMBTUbbl
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 2,017
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
NYMEX 2018 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	126,600
Average Price | $ / MMBTU	3
NYMEX 2018 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	121,600
Average Price | $ / MMBTU	3
NYMEX 2018 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	117,040
Average Price | $ / MMBTU	3
NYMEX 2,018
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	497,328
Average Price | $ / MMBTU	3
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 2,019
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 2,020
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

Derivative And Financial Inst47

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, 2017USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)item	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)
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

Derivative And Financial Inst48

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

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)	May 19, 2016USD ($)
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
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		4
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%

Oil And Natural Gas Propertie50

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

Oil And Natural Gas Propertie51

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

Oil And Natural Gas Propertie52

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

Asset Retirement Obligation (De

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

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2017USD ($)a	Sep. 30, 2016USD ($)	Dec. 31, 2016USD ($)
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

Investments (Details)

Investments (Details) - USD ($) $ in Thousands	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

Investments (Summarized Financi

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

Commitments And Contingencies (

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

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	Nov. 22, 2016USD ($)	Jul. 05, 2016USD ($)	Oct. 14, 2015aMcfbbl	Nov. 30, 2016USD ($)itemshares	Jun. 30, 2017USD ($)	Sep. 30, 2017USD ($)a$ / MMBTU	Sep. 30, 2017USD ($)a	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)
Related Party Transaction [Line Items]
Related parties, net receivable						$ 6.7	$ 6.7		$ 6
Related parties, net payable						$ 6.5	$ 6.5		$ 7
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
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				$ 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%

Unit-Based Compensation (Restri

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

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	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

Partners' Capital (Details)

Partners' Capital (Details) $ / shares in Units, $ in Thousands

May 22, 2017shares

Feb. 20, 2017shares

Jan. 25, 2017$ / sharesshares

Oct. 14, 2015USD ($)$ / sharesshares

Apr. 30, 2017USD ($)shares

Nov. 30, 2016USD ($)shares

Aug. 31, 2015

Jun. 30, 2017shares

Mar. 31, 2017shares

Dec. 31, 2016shares

Sep. 30, 2016shares

Dec. 31, 2015

Sep. 30, 2017USD ($)shares

Dec. 06, 2016shares

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

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

Partners Capital (Class B Prefe

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

Partners' Capital (EPU) (Detail

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

Reporting Segments (Segment Inf

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

Reporting Segments (Assets by S

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

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	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

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions	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
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