Evolve Transition Infrastructure (SNMP) 10-Q 12 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 11, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
Entity Registrant Name	Sanchez Production 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		4,279,517
Entity Current Reporting Status	Yes

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Revenues
Natural gas sales	$ 600	$ 3,642	$ 4,275	$ 10,216
Oil sales	(2,756)	639	2,587	5,603
Natural gas liquid sales	244	500	520	886
Gathering and transportation sales	14,258		28,133
Total revenues	12,346	4,781	35,515	16,705
Operating expenses:
Lease operating expenses	4,178	5,358	9,151	10,258
Transportation operating expenses	3,014		6,068
Cost of sales	63	125	193	330
Production taxes	326	583	547	953
General and administrative	4,978	3,351	10,697	10,906
Unit compensation expense	1,091	395	1,529	2,387
Gain on sale of assets		(54)		(113)
Depreciation, depletion and amortization	6,129	3,079	13,317	6,199
Asset impairments		862	1,309	83,727
Accretion expense	315	264	630	517
Total operating expenses	20,094	13,963	43,441	115,164
Other expense (income)
Interest expense	1,103	1,122	2,002	1,768
Gain on embedded derivatives	(6,898)		(13,192)
Other expense (income)	(1)	37	(61)	100
Total other expenses (income)	(5,796)	1,159	(11,251)	1,868
Total expenses	14,298	15,122	32,190	117,032
Net income (loss)	(1,952)	(10,341)	3,325	(100,327)
Less:
Preferred unit paid-in-kind distributions		(524)		(524)
Preferred unit distributions	(8,750)		(17,500)
Preferred unit amortization	(6,505)		(13,772)
Net income (loss) attributable to common unitholders	(17,207)	$ (10,865)	(27,947)	$ (100,851)
Class A Unit [Member]
Loss per unit
Net loss per unit - Basic and diluted				$ (0.38)
Weighted Average Units Outstanding - Basic and diluted				48,451
Class B Unit [Member]
Loss per unit
Net loss per unit - Basic and diluted				$ (0.31)
Weighted Average Units Outstanding - Basic and diluted				2,879,163
Common Units [Member]
Other expense (income)
Net income (loss)			3,325
Less:
Net income (loss) attributable to common unitholders	$ (17,207)		$ (27,947)
Loss per unit
Net loss per unit - Basic and diluted	$ (4.37)	$ (3.49)	$ (8.38)	$ (32.37)
Weighted Average Units Outstanding - Basic and diluted	3,935,297	3,113,428	3,333,482	3,087,431

Condensed Consolidated Stateme3

Condensed Consolidated Statements Of Operations (Parenthetical)	Aug. 03, 2015
Condensed Consolidated Statements Of Operations [Abstract]
Reverse stock split ratio	0.1

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 1,203	$ 6,571
Restricted cash		600
Accounts receivable	1,663	2,461
Accounts receivable - related entities	7,351	1,515
Prepaid expenses	2,159	744
Fair value of derivative instruments	8,650	21,010
Total current assets	21,026	32,901
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	731,977	732,088
Gathering and transportation assets	147,695	147,479
Material and supplies	1,056	1,056
Less accumulated depreciation, depletion, amortization, accretion and impairments	(662,099)	(653,569)
Oil and natural gas properties and equipment, net	218,629	227,054
Other assets
Intangible assets, net	192,824	199,741
Fair value of derivative instruments	6,054	10,008
Other non-current assets	1,524	1,596
Total assets	440,057	471,300
Current liabilities
Accounts payable and accrued liabilities	1,780	7,288
Accounts payable and accrued liabilities - related entities	3,669	1,035
Royalties payable	499	689
Total current liabilities	5,948	9,012
Other liabilities
Asset retirement obligation	19,515	20,364
Embedded derivatives	179,885	193,077
Long-term debt, net of debt issuance costs	107,091	104,909
Total other liabilities	306,491	318,350
Total liabilities	312,439	327,362
Mezzanine equity
Class B preferred units, 19,444,445 units issued and outstanding as of June 30, 2016 and December 31, 2015, respectively	186,264	172,111
Partners' capital
Total members' equity/partners' capital (deficit)	(58,646)	(28,173)
Total liabilities and members' equity/partners' capital	440,057	471,300
Class A Preferred [Member]
Partners' capital
Class A preferred units, zero units issued and outstanding as of June 30, 2016 and 11,409,131 units issued and outstanding as of December 31, 2015		17,112
Total members' equity/partners' capital (deficit)		17,112
Common Units [Member]
Partners' capital
Common units, 4,279,517 units issued and outstanding as of June 30, 2016 and 3,240,812 units issued and outstanding as of December 31, 2015	(58,646)	(45,285)
Total members' equity/partners' capital (deficit)	$ (58,646)	$ (45,285)

Condensed Consolidated Balance5

Condensed Consolidated Balance Sheets (Parenthetical)	Jun. 30, 2016shares	Dec. 31, 2015shares
Class B preferred units, issued	19,444,445	19,444,445
Class B preferred units, outstanding	19,444,445	19,444,445
Class A Preferred [Member]
Class A preferred units, issued	0	11,409,131
Class A preferred units, outstanding	0	11,409,131
Common Units [Member]
Units, issued	4,279,517	3,240,812
Units, outstanding	4,279,517	3,240,812

Condensed Consolidated Stateme6

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash flows from operating activities:
Net income (loss)	$ 3,325	$ (100,327)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	7,262	6,011
Amortization of intangible assets	6,917	188
Asset impairments	1,309	83,727
Amortization of debt issuance costs	246	324
Accretion expense	630	517
Revisions to asset retirement obligation included in DD&A	(862)
Equity earnings in affiliate	(12)	48
Gain from disposition of property and equipment	(9)	(113)
Bad debt expense	35	122
Total mark-to-market on commodity derivative contracts	3,736	1,066
Cash mark-to-market settlements on commodity derivative contracts	13,028	8,950
Unit-based compensation programs	1,952	2,388
Gain on embedded derivative	(13,192)
Costs for plug and abandon activities	(86)
Changes in Operating Assets and Liabilities:
Decrease in accounts receivable	313	1,721
Increase in accounts receivable - related entities	(5,836)	(1,582)
Increase in accounts payable - related entities	2,634
(Increase) decrease in prepaid expenses	(1,414)	408
(Increase) decrease in other assets	659	(981)
(Decrease) increase in accounts payable/accrued liabilities	(3,128)	2,788
Decrease in royalties payable	(190)	(399)
Net cash provided by operating activities	17,317	4,856
Cash flows from investing activities:
Cash paid for acquisitions		(81,378)
Development of oil and natural gas properties	(2,269)	(1,056)
Proceeds from sale of assets	16	344
Distributions from equity affiliate		15
Net cash used in investing activities	(2,253)	(82,075)
Cash flows from financing activities:
Proceeds from issuance of preferred units		17,375
Payments for offering costs	(87)	(810)
Proceeds from issuance of debt	2,000	106,000
Repayment of debt		(42,500)
Issuance of common units		52
Repurchase of common units under repurchase program	(2,948)
Units tendered by employees for tax withholdings	(140)	(618)
Distributions to unitholders	(3,025)
Class B preferred unit cash distributions	(16,168)
Debt issuance costs	(64)	(1,294)
Net cash provided by (used in) financing activities	(20,432)	78,205
Net increase (decrease) in cash and cash equivalents	(5,368)	986
Cash and cash equivalents, beginning of period	6,571	4,238
Cash and cash equivalents, end of period	1,203	5,224
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	(1,609)	(149)
Acquisition of oil and natural gas properties in exchange for common units		2,000
Cash paid during the period for interest	$ (1,732)	(1,154)
Cash paid during the period for income taxes		$ (2)

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Changes in Members’ Equity/Partners’ Capital - USD ($) $ in Thousands	Class A Unit [Member]	Class B Unit [Member]	Class A Preferred [Member]	Common Units [Member]	Total
Balance at Dec. 31, 2014	$ 1,930	$ 104,893			$ 106,823
Balance (in shares) at Dec. 31, 2014	48,451	2,879,258
Units tendered by employees for tax withholding		$ (21)			(21)
Units tendered by employees for tax withholding (in shares)		(1,557)
Net income (loss)	$ (18)	$ (905)			(923)
Balance at Mar. 05, 2015	$ 1,912	$ 103,967			105,879
Balance (in shares) at Mar. 05, 2015	48,451	2,877,701
Class A Units converted to common units	$ (1,912)			$ 1,912
Class A Units converted to common units (in shares)	(48,451)			58,729
Class B Units converted to common units upon limited partnership conversion		$ (103,967)		$ 103,967
Class B Units converted to common units upon limited partnership conversion (in shares)		(2,877,701)		2,877,701
Units tendered by employees for tax withholding				$ (597)	(597)
Units tendered by employees for tax withholding (in shares)				(32,269)
Unit-based compensation programs				$ 2,454	2,454
Unit-based compensation programs (in shares)				472,972
Private placement of Class A Preferred Units, net of offering costs			$ 16,550		16,550
Private placement of Class A Preferred Units, net of offering costs (in shares)			10,859,375
Beneficial conversion feature of Class A Preferred Units			$ (863)	$ 863
Preferred unit paid-in-kind distributions			$ 1,425	(1,425)
Preferred unit paid-in-kind distributions (in shares)			834,989
Issuance of common units				$ 193	193
Issuance of common units (in shares)				6,865
Common units retired via unit repurchase program				$ (2,223)	(2,223)
Common units retired via unit repurchase program (in shares)				(143,185)
Common units issued for acquisition of properties				$ 2,000	2,000
Common units issued for acquisition of properties (in shares)				105,263
Common units received and retired for acquisition of properties				$ (1,065)	(1,065)
Common units received and retired for acquisition of properties (in shares)				(105,263)
Cash distributions				$ (1,219)	(1,219)
Distributions - Class B preferred units				(14,012)	(14,012)
Net income (loss)				(136,133)	(136,133)
Balance at Dec. 31, 2015			$ 17,112	$ (45,285)	(28,173)
Balance (in shares) at Dec. 31, 2015			11,694,364	3,240,813
Class A Units converted to common units			$ (17,112)	$ 17,112
Class A Units converted to common units (in shares)			(11,694,364)	1,169,441
Units tendered by employees for tax withholding				$ (140)	(140)
Units tendered by employees for tax withholding (in shares)				(12,227)
Unit-based compensation programs				$ 1,952	1,952
Unit-based compensation programs (in shares)				67,627
Units forfeited by employees (in shares)				(2,000)
Issuance of common units				$ 771	771
Issuance of common units (in shares)				58,363
Common units retired via unit repurchase program				$ (2,948)	(2,948)
Common units retired via unit repurchase program (in shares)				(242,500)
Cash distributions				$ (3,025)	(3,025)
Distributions - Class B preferred units				(30,408)	(30,408)
Net income (loss)				3,325	3,325
Balance at Jun. 30, 2016				$ (58,646)	$ (58,646)
Balance (in shares) at Jun. 30, 2016				4,279,517

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Changes in Members’ Equity/Partners’ Capital (Parenthetical) $ in Millions	Dec. 31, 2015USD ($)
Class A Preferred [Member]
Offering costs	$ 0.8

Organization And Business

Organization And Business	6 Months Ended
	Jun. 30, 2016
Organization And Business [Abstract]
Organization And Business	1. ORGANIZATION AND BUSINESS Organization Sanchez Production Partners LP, a Delaware limited partnership ( together with our consolidated subsidiaries “SPP”, “we”, “us”, “our” or the “Partnership”), is a publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy production assets. SPP 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 and 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. The Manager owns the general partner of SPP and all of SPP’s incentive distribution rights. Our common units are currently listed on the NYSE MKT under the symbol “SPP.” Historically, our operations have consisted of the exploration and 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 (“SN”) and entered into a 15 -year gathering and processing agreement with SN. In July 2016, we sold a significant portion of our oil and gas properties in the Mid-Continent region. As a result of the acquisition of midstream assets from SN and the disposition of our oil and gas properties located in the Mid-Continent region, our historical financial statements (including those in this Form 10-Q) will differ substantially from our future financial statements beginning with the quarter ending December 31, 2015, principally because a significant portion of our revenues now come from the long-term, fee-based gathering and processing agreement with SN rather than from oil and natural gas production.

Basis Of Presentation And Summa

Basis Of Presentation And Summary Of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2016
Basis Of Presentation And Summary Of Significant Accounting Policies [Abstract]
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 SPP and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. We conduct our business activities as two operating segments: (1) the exploration and production of oil and natural gas and (2) the midstream business, which includes the Catarina gathering system. 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 the Company and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2015, which was filed with the SEC on March 30, 2016. 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 March 2016, the FASB issued Accounting Standards Update (“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. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued Accounting Standards Update 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. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments,” effective for annual and interim periods beginning after December 15, 2015. ASU 2015-16 eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. During the first quarter of 2016, the Company adopted ASU 2015-16. Adoption of this guidance did not have a material impact on our consolidated financial statements and footnote disclosures. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. In August 2015, the FASB issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” The guidance in ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements. ASU 2015-15 states given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. During the first quarter of 2016, the Company adopted ASU 2015-03 and ASU 2015-15 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of debt issuance costs of approximately $2,091 Decrease in Debt issuance costs (Other Assets) of approximately $2,091 In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. During the first quarter of 2016, the Company adopted ASU 2015-02. Adoption of this guidance did not have a material impact on our consolidated financial statements and footnote disclosures. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” 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 guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. Reclassifications Certain reclassifications have been made to the prior period to conform to the current period presentation. These reclassifications had no effect on total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities. In accordance with ASU No. 2015-03 and ASU No. 2015-15, debt issuance costs are to be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. As such, debt issuance costs, net of amortization, at December 31, 2015 of $2.1 million have been reclassified from other assets to other liabilities, effectively eliminating the debt issuance cost line and reducing long-term debt in the balance sheet. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (“NGLs”); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. Significant Accounting Policies Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2015. Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash. Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on. There were no checks-in-transit reported in accounts payable as of June 30, 2016 or December 31, 2015. Restricted Cash As of June 30, 2016 , we had no restricted cash. As of December 31, 2015, we had approximately $ 0 .6 million of restricted cash held in escrow that related to a vendor dispute that remained in the escrow account until the dispute was resolved in March 2016. Accounts Receivable, Net Our accounts receivable are primarily from purchasers of oil and natural gas, gathering and transportation sales, and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. As of June 30, 2016 and December 31, 2015, we had an allowance for doubtful accounts receivable of $0.1 million and $0.4 million, respectively.

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2016
Acquisitions [Abstract]
Acquisitions	3. ACQUISITIONS Eagle Ford Acquisition On March 31, 2015, we completed an acquisition of wellbore interests in certain producing oil and natural gas properties in Gonzales County, Texas (the “Eagle Ford properties,” and such acquisition, the “Eagle Ford acquisition”) located in the Eagle Ford Shale in Gonzales County, Texas from SN for a purchase price of $85 million, subject to normal and customary closing adjustments. The effective date of the transaction was January 1, 2015. The acquisition included initial conveyed working interests and net revenue interests for each property that escalate on January 1 for each year from 2016 through 2019, at which point, SPP’s interests in the Eagle Ford properties will stay constant for the remainder of the respective lives of the assets. The adjusted purchase price of $83.4 million was funded at closing with net proceeds from the private placement of 10,625,000 newly created Class A Preferred Units , which were issued for a cash purchase price of $1.60 per unit, resulting in gross proceeds to SPP of $17.0 million, the issuance of 1,052,632 common units (approximately 105,263 common units after adjusting for a reverse unit split) to SN, borrowings under the Partnership’s Credit Agreement (as defined in Note 6, “Long-Term Debt”), and available cash. 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 $ Facilities Fair value of hedges assumed Fair value of assets acquired Asset retirement obligations Ad valorem tax liability Fair value of net assets acquired $ Western Catarina Midstream Acquisition On October 14, 2015, we completed an acquisition of midstream assets located in Western Catarina, in the Eagle Ford Shale in South Texas from SN for a purchase price of $345.8 million, subject to normal and customary closing adjustments (the “Western Catarina Midstream acquisition”). The purchase price was funded at closing with net proceeds from the sale of Class B Preferred Units to Stonepeak Catarina Holdings LLC, an affiliate of Stonepeak Infrastructure Partners (“Stonepeak”) and available cash. Additionally, as a result of the Western Catarina Midstream acquisition, we repurchased 105,263 common units previously held by a subsidiary of SN. 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): Fixed assets $ Contractual customer relationships Purchase of SPP common units from SN Fair value of assets acquired $ Pro Forma Operating Results (Unaudited) The following unaudited pro forma combined financial information for the six months ended June 30, 2016 and 2015 reflect the consolidated results of operations of the Partnership as if the Western Catarina Midstream and Eagle Ford acquisitions and related financings had occurred on January 1, 2015. The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, amortization of customer contract intangible assets acquired and paid-in-kind units issued in connection with the Class A Preferred Units. The unaudited pro forma combined financial statements give effect to the events set forth below: · The Western Catarina Midstream acquisition completed on October 14, 2015. · Issuance of Class B Preferred Units to finance the Western Catarina Midstream acquisition. · Repurchase of common units issued to finance a portion of the Eagle Ford acquisition as a part of the Western Catarina Midstream acquisition, and the related effect on net income (loss) per common unit. · The Eagle Ford acquisition completed on March 31, 2015. · The increase in borrowings under the Credit Agreement to finance a portion of the Eagle Ford acquisition, and the related adjustments to interest expense. · Issuance of common units to finance a portion of the Eagle Ford acquisition and the related effect on net income (loss) per common unit (in thousands, except per unit amounts). Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 Revenues $ $ $ $ Net income (loss) attributable to common unitholders $ $ $ $ Net income (loss) per unit prior to conversion Class A units - Basic and diluted $ — $ — $ — $ Class B units - Basic and diluted $ — $ — $ — $ Net income (loss) per unit after conversion Common units - Basic and diluted $ $ $ $ The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Partnership would have reported had the Western Catarina Midstream and Eagle Ford acquisitions and related financings been completed as of the date set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Partnership’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results. Post-Acquisition Operating Results The amounts of revenue and excess of revenues over direct operating expenses included in the Partnership’s condensed consolidated statements of operations for the three and six months ended June 30, 2016, for the Eagle Ford and Western Catarina Midstream acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Three Months Ended Six Months Ended June 30, 2016 June 30, 2016 Revenues $ $ Excess of revenues over direct operating expenses $ $

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Measurements [Abstract]
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). The valuation models used to value derivatives associated with the Partnership's oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. 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 June 30, 2016 (in thousands): Fair Value Measurements at June 30, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral June 30, 2016 Derivative assets $ — $ $ — $ — $ Derivative liabilities — — — — — Embedded derivative — — Total net assets $ — $ $ $ — $ 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, 2015 (in thousands): Fair Value Measurements at December 31, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2015 Derivative assets $ — $ $ — $ — $ Derivative liabilities — — — — — Embedded derivative — — Total net assets $ — $ $ $ — $ As of June 30, 2016 and December 31, 2015, 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 Accounting Standards Codification (“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. The fair values of oil and natural gas properties and asset retirement obligations 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. Our purchase price allocation for the Eagle Ford acquisition is presented in Note 3, ‘‘Acquisitions.” Fair value of oil and natural gas properties are presented in Note 7, “Oil and Natural Gas Properties.” A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 8 , ‘‘Asset Retirement Obligation .’’ 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 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 June 30, 2016. 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 consummated a contract for the sale of preferred units in October 2015 which contained provisions that must be bifurcated from the contract and valued as a derivative. The embedded derivative is valued through the use of a Monte Carlo model which utilizes observable inputs, the Partnership’s unit prices at various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. As a result, we have classified the fair value measurements of our embedded derivative as Level 3 inputs. The Partnership has marked this derivative to market as of June 30 , 2016, and incurred an approximate $13. 2 million gain as a result. The gain is the result in the reduction in fair value of the embedded derivative due to the decrease in unit price. The fair value of the Partnership’s embedded derivative classified as Level 3 as of June 30 , 2016 was $1 79.9 million. Changes in the unobservable inputs will impact the fair value measurement of the Partnership's embedded derivative contract. 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 six months ended June 30, 2016 and the year ended December 31, 2015 (in thousands): Significant Unobservable Inputs (Level 3) June 30, December 31, 2016 2015 Beginning balance $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Ending balance $ $ Gain (loss) included in earnings related to derivatives still held as of June 30, 2016, and December 31, 2015 $ $

Derivative And Financial Instru

Derivative And Financial Instruments	6 Months Ended
	Jun. 30, 2016
Derivative And Financial Instruments [Abstract]
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 transactions are normally price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. 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 and liquids sales in the condensed consolidated statements of operations. As of June 30 , 2016, 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) For the Quarter Ended June 30, 2016 (volume in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ Fixed Price Swaps—NYMEX (Henry Hub) For the Quarter Ended June 30, 2016 (volume in Mcfs) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the six months ended June 30, 2016 and the year ended December 31, 2015 (in thousands): June 30, December 31, 2016 2015 Beginning fair value of commodity derivatives $ $ Net gains (losses) on crude oil derivatives Net gains (losses) on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Ending fair value of commodity derivatives $ $ 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 For the Three Months Ended June 30, For the Six Months Ended June 30, Derivative Type in Income 2016 2015 2016 2015 Commodity – Mark-to-Market Oil sales $ $ $ $ Commodity – Mark-to-Market Natural gas sales $ $ $ $ Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with three 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. As of June 30, 2016 and December 31, 2015, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. Hedges Novated in the Eagle Ford Acquisition As a part of the Eagle Ford acquisition, we received by novation from the seller certain hedges covering approximately 90% , 85% , 85% and 80% of estimated 2016, 2017, 2018 and 2019 oil and natural gas production from the acquired assets, respectively. The counterparty for the hedges is a lender in the Partnership’s Credit Agreement. The Partnership is responsible for all future periodic settlements of these transactions. As of June 30 , 2016, the fair value of the hedges assumed resulted in an $8.9 million asset in our condensed consolidated balance sheet. Embedded Derivative The Partnership consummated a contract for the sale of preferred units in October 2015 which contained provisions that must be bifurcated from the contract and valued as a derivative. The embedded derivative is valued through the use of a Monte Carlo model which utilizes observable inputs, the Partnership’s unit prices at various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. The Partnership has marked this derivative to market as of June 30 , 2016, and incurred an approximate $ 13.2 million gain as a result. The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the quarters ended June 30 , 2016 and the year ended December 31, 2015 (in thousands): June 30, December 31, 2016 2015 Beginning fair value of embedded derivative $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Ending fair value of embedded derivative $ $

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2016
Long-Term Debt [Abstract]
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 facility provides a maximum commitment of $500,000,000 and has a maturity date of March 31, 2020. Borrowings under the credit facility 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 facility is limited to the borrowing base for our oil and natural gas properties and our midstream assets. Borrowings under the credit facility are available for direct investment in oil and gas properties, acquisitions, and working capital and general business purposes. The credit facility has a sub-limit of $15,000,000 which may be used for the issuance of letters of credit. The initial borrowing base under the credit facility was $200,000,000 . The borrowing base for the credit available for the upstream oil and gas properties is re-determined semi-annually in the second and fourth quarters of the year, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time. The borrowing base for the credit available for our midstream properties is equal to the rolling four quarter EBITDA of our midstream operations multiplied by 4.75 for the second quarter of 2016 and 4.5 thereafter. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders. On May 19, 2016, and June 1, 2016, respectively, SPP received notification that its lenders completed a semi-annual review of the RBL Component and quarterly review of the Midstream Component of the partnership ’s borrowing base pursuant to the terms of its credit facility. Based on these review s , the borrowing base has been established at $ 1 95.7 million. At our election and as of June 30, 2016 , interest for borrowings under the credit facility are determined by reference to (i) the London interbank rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum based on utilization or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum based on utilization plus (iii) a commitment fee between 0.375% and 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 facility 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 facility 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 facility and exercise other rights and remedies. The credit facility 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 facility, 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 facility 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 June 30, 2016, we were in compliance with the financial covenants contained in the credit facility. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our credit facility 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 facility, such that our outstanding debt could become then due and payable. We may request waivers of compliance for any violat ion of a financial covenant from the lenders, but there is no assurance that such waivers would be granted. During the first quarter of 2016, the Company adopted ASU 2015-03 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of debt issuance costs of approximately $2,091 Decrease in Debt issuance costs, net (Other Assets) of approximately $2,091 Debt Issuance Costs As of June 30, 2016, our unamortized debt issuance costs were $1.9 million. These costs are amortized to interest expense in our consolidated statement of operations over the life of our credit facility. At December 31, 2015, our unamortized debt issuance costs were $2.1 million.

Oil And Natural Gas Properties

Oil And Natural Gas Properties	6 Months Ended
	Jun. 30, 2016
Oil And Natural Gas Properties [Abstract]
Oil And Natural Gas Properties	7. OIL AND NATURAL GAS PROPERTIES Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas exploration, development and production activities. Leasehold acquisition costs, property acquisition and the costs of development of proved areas are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred. Oil and natural gas properties consisted of the following (in thousands): June 30, December 31, 2016 2015 Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ $ Unproved property Land Total property costs Materials and supplies Total Less: Accumulated depreciation, depletion, amortization and impairments Oil and natural gas properties and equipment, net $ $ Gathering and transportation assets consist of the following (in thousands): June 30, December 31, 2016 2015 Gathering and transportation assets Catarina midstream assets $ $ Less: Accumulated depreciation, depletion, amortization Total gathering and transportation assets $ $ 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 Six Months Ended June 30, June 30, 2016 2015 2016 2015 DD&A of oil and natural gas-related assets $ $ $ $ DD&A of gathering and transportation related assets — — Total DD&A Asset impairments — Total $ $ $ $ Impairment of Oil and Natural Gas Properties and Other Non-Current Assets. Oil and natural gas properties are rev iewed for impairment on a field-by- field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third- party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other significant inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (i) future operating and development costs; (ii) future commodity prices; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Cash flow estimates for impairment testing exclude derivative instruments. For the three months ended June 30, 2016, we did not record non-cash impairment charges. For the six months ended June 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. For the three and six months ended June 30, 2015, we recorded non-cash charges of $0.9 million and $83.7 million, respectively, to impair the value of our Cherokee Basin properties, Woodford Shale properties and our Texas and Louisiana properties acquired prior to the Eagle Ford acquisition . The carrying values of the impaired proved properties were reduced to fair value of $75 . 8 million as of June 30, 2016 , estimated using inputs characteristic of a Level 3 fair value measurement. 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 six months ended June 30, 2016 or 2015.

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation [Abstract]
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. Subsequently, the ARC is depreciated using a systematic and rational method over the asset’s useful life. 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): June 30, December 31, 2016 2015 Asset retirement obligation, beginning balance $ $ Liabilities added from acquisitions — Liabilities added from drilling — — Sold — Revisions to cost estimates Settlements Accretion expense Asset retirement obligation, ending balance $ $ Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for AROs. As of June 30, 2016 and December 31, 2015, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the year ended December 31, 2015, revisions were made to the ARO liability based on recent costs incurred on abandoned wells, which were lower on average than originally projected.

Intangible Assets

Intangible Assets	6 Months Ended
	Jun. 30, 2016
Intangible Assets
Intangible Assets	9. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $192.3 million related to the customer contract with SN that was agreed to as part of the Western Catarina Midstream a cquisition. Pursuant to the 15 -year agreement, SN 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 the gathering system, 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. The remaining $0.5 million of the intangible assets balance is comprised of marketing contracts from the 2007 New field a cquisition which are being amortized using the straight-line method over the 10 year life of the agreement. Amortization expense for the six months ended June 30, 2016 and 2015 was $6.9 million and $0.2 million , respectively . Intangible assets as of June 30, 2016 and December 31, 2015 are detailed below (in thousands): June 30, December 31, 2016 2015 Beginning balance $ $ Additions — Amortization Ending balance $ $

Commitments And Contingencies

Commitments And Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments And Contingencies [Abstract]
Commitments And Contingencies	10. COMMITMENTS AND CONTINGENCIES We did not have any material commitments and contingencies as of June 30 , 2016.

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	11. 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 and acquisition, disposition and financing services. In connection with providing services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, is paid in cash unless Manager elects for such fee to be paid in our equity. The Services Agreement has a ten -year term and will be automatically renewed for an additional ten years unless both Manager and the Company provide notice to terminate the agreement. During the six months ended June 30, 2016, we expensed $3.0 million to Manager pursuant to the Services Agreement. During the six months ended June 30, 2015, we paid $2.4 million to Manager under the Services Agreement, which included a prepayment of $0.5 million that was applied to the third quarter of 2015. Manager utilizes SOG to provide the services under the Services Agreement. In May 2014, we entered into a Contract Operating Agreement with SOG pursuant to which SOG either provides services to operate, develop and produce our oil and natural gas properties or engages a third-party operator to do so, other than with respect to our properties in the Mid-Continent Region. We also have entered into the Geophysical Seismic Data Use License Agreement with SOG pursuant to which SOG provides us a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to our oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors. The Partnership has entered into a Firm Gathering and Processing Agreement with SN for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream, LLC (“Catarina Midstream”). In addition, for the first five years of the Gathering Agreement, SN Catarina, LLC 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. As of June 30, 2016 and December 31, 2015, the Partnership had a net receivable from related parties of $7.4 million and $1.5 million, respectively, which are included in “Accounts receivable – related entities” in the condensed consolidat ed balance sheets. As of June 30, 2016 and December 31, 2015, the Partnership also had a net payable from related parties of $3.7 million and $1.0 million, respectively. The net receivables/payable as of June 30, 2016 and December 31, 2015 consist primarily of revenues receivable from oil and natural gas production, offset by costs associated with that production and obligations for general and administrative costs. On March 31, 2015, the Partnership and SN entered into a Purchase and Sale Agreement for the Eagle Ford acquisition for total consideration of $85.0 million. After $1.4 million in normal and customary closing adjustments, consideration paid at closing consisted of $81.6 million cash paid by us to SN and 105,263 of our common units issued to SN with an aggregate consideration value of $2,000,000 . All 105,263 common units issued as consideration for the Eagle Ford acquisition were repurchased in connection with the Western Catarina Midstream acquisition in October 2015. See further discussion of the transaction in Note 3, “Acquisitions.” In October 2015, the Partnership and SN consummated the Western Catarina Midstream acquisition for total consideration of approximately $345.8 million in cash, subject to closing and post-closing adjustments. Concurrently with the signing of the Western Catarina Midstream acquisition purchase and sale agreement, we entered into a 15 -year gas gathering and processing agreement with SN. For the six months ended June 30, 2016, SN paid us appro ximately $23.2 mil lion pursuant to the terms of the gathering and processing agreement. See further discussion of the transaction in Note 3, “Acquisitions .” On July 5, 2016, the Partnership entered into an agreement with SN and SN Midstream, LLC, a wholly-owned subsidiary of SN, to purchase 50% of the issued and outstanding membership interests in Carnero Gathering, LLC (see further discussion in Note 16, “Subsequent Events”).

Unit-Based Compensation

Unit-Based Compensation	6 Months Ended
	Jun. 30, 2016
Unit-Based Compensation [Abstract]
Unit-Based Compensation	12. UNIT-BASED COMPENSATION Prior to our conversion to a Delaware limited partnership on March 6, 2015, we granted restricted common unit awards to certain employees in Texas under the 2009 Omnibus Incentive Compensation Plan (the “Omnibus Plan”). The Omnibus Plan provided for a variety of unit-based and performance-based awards, including unit options, restricted units, unit grants, notional units, unit appreciation rights, performance awards and other unit-based awards. Additionally, prior to March 6, 2015, we granted restricted common unit awards to certain field employees in Kansas and Oklahoma and to certain employees in Texas under our previous Long-Term Incentive Plan (the “Previous LTIP”). After our conversion to a limited partnership, both the Omnibus Plan and the Previous LTIP had no outstanding units remaining. Effective March 6, 2015, the Omnibus Plan was amended and restated and renamed the Sanchez Production Partners LP Long-Term Incentive Plan (the “LTIP”) and the Previous LTIP was merged into the LTIP. Restricted unit activity under the Omnibus Plan, the Previous LTIP, and the LTIP during the period, after adjusting for the 1 -for-10 reverse split completed on August 3, 2015 , is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2015 $ Granted Vested Returned/Cancelled Outstanding at June 30, 2016 $ During the year ended December 31, 2015, the Partnership issued 346,925 restricted common units ( 34,693 restricted common units after adjusting for reverse unit split) pursuant to the LTIP to the directors of the Partnership’s general partner that vested immediately on the date of the grant. The unit based compensation expense for the awards were based on their grant date fair values. In March 2015, officers were granted a total of 1,025,641 restricted common units ( 102,564 restricted common units after adjusting for the reverse unit split) that were due upon request, of which 769,231 restricted common units ( 76,923 restricted common units after adjusting for reverse unit split) were vested and delivered at the request of the officers, net of 322,692 restricted common units ( 32,269 restricted common units after adjusting for reverse unit split) that were returned to the plan for settlement of taxes associated with the vesting . Furthermore, on December 1, 2015, the board of directors of our general partner approved the grant of 335,715 restricted units pursuant to the LTIP to employees, service providers, and executive officers that which are set to vest pro-rata over a three -year period. In April 2016, officers were granted a total of 67,627 restricted common units that were vested and delivered. As of June 30, 2016, 213,273 common units remain available for future issuance to participants under the LTIP.

Distributions To Unitholders

Distributions To Unitholders	6 Months Ended
	Jun. 30, 2016
Distributions To Unitholders [Abstract]
Distributions To Unitholders	13. DISTRIBUTIONS TO UNITHOLDERS From the second quarter of 2009 through the second quarter of 2015, we did not pay distributions on our common units. Starting in the third quarter of 2015, the board of directors of our general partner declared distributions of Class A Preferred Units on August 10, 2015 and November 10, 2015 to holders as of August 14, 2015 and November 16, 2015, respectively. A total of 549,756 paid-in-kind units were distributed for the year ended December 31, 2015. On November 30, 2015, we paid a cash distribution with respect to the quarter ended September 30, 2015 in the amount of $0.400 per common unit. On February 9, 2016, we announced that the board of directors of our general partner approved a cash distribution of $0.406 per common unit for the fourth quarter of 2015. The Partnership also declared a fourth quarter 2015 paid-in-kind distribution of 2.5% on its Class A preferred units and a fourth quarter prorated cash distribution of $0.3815 on its Class B preferred units. The distributions were paid on February 29 , 2016 to unitholders of record on February 19, 2016. On May 10, 2016, we announced that the board of directors of our general partner approved a cash distribution of $0.4121 per common unit and $0.450 per Class B preferred unit for the first quarter of 2016. The distributions were paid on May 31, 2016 to unitholders of r e cord on May 20, 2016. All Class A preferred Units were converted to common units on a one to one basis at March 31, 2016; as such, no paid-in-kind distributions were made on Class A Preferred Units for the second quarter of 2016. On August 10, 2016, we announced that the board of directors of our general partner approved a cash distribution of $0.4183 per common unit and $0.450 per Class B preferred unit for the second quarter of 2016. The distributions are payable on August 31, 2016 to unitholders of record on August 22 , 2016 .

Members' Equity_Partners' Capit

Members' Equity/Partners' Capital	6 Months Ended
	Jun. 30, 2016
Members' Equity/Partners' Capital [Abstract]
Members' Equity/Partners' Capital	14. MEMBERS’ EQUITY/PARTNERS’ CAPITAL Outstanding Units As of June 30, 2016, we had no Class A Preferred Units outstanding, 19,444,445 Class B Preferred Units outstanding, and 4,279, 517 common units outstanding. Common Unit Issuances On March 31, 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. In April 2015, we entered into an at-the-market sales agreement with MLV & Co. LLC to sell from time-to-time up to $100 million of our common units, with any proceeds from such sales to be used for general limited partnership purposes. We did not sell any common units during the six months ended June 30 , 2016. On August 3, 2015, the Partnership effected a 1 -for-10 reverse split on its common units, pursuant to which common unitholders received one common unit for every ten common units held at the close of trading on August 3, 2015. All fractional units created by the reverse split were rounded to the nearest whole unit. Each unitholder received at least one unit. Post-split units of the Partnership began trading on August 4, 2015. Immediately prior to the reverse unit split, there were 31,495,506 common units of the Partnership issued and outstanding , with a per unit closing trading price on the NYSE MKT on August 3, 2015 of $1.55 . Immediately after the reverse unit split, the number of issued and outstanding common units of the Partnership decreased to 3,149,551 , not inclusive of common units required by DTCC due to the rounding up of fractional units at the beneficial level, and the per unit opening trading price on the NYSE MKT was $15.50 . Preferred Unit Issuance Class A Preferred Unit Offerings: On March 31, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement with the purchasers named on Schedule A thereto (collectively, the “March Purchasers”), pursuant to which the Partnership sold, and the March Purchasers purchased, 10,625,000 of the Partnership’s newly created Class A Preferred Units (the “Class A Preferred Units”) in a privately negotiated transaction for an aggregate cash purchase price of $1.60 per Class A Preferred Unit resulting in gross proceeds to the Partnership of $17 million. The Partnership used the net proceeds of $17 million from this transaction, together with common units issued to SN, borrowings under our credit facility, and available cash on hand, to pay the consideration for the Eagle Ford acquisition. Additionally, on April 15, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement with the purchasers named on Schedule A thereto (collectively, the “April Purchasers”), pursuant to which the Partnership sold, and the April Purchasers purchased, 234,375 of the Partnership’s Class A Preferred Units in a privately negotiated transaction for an aggregate cash purchase price of $1.60 per Class A Preferred Unit resulting in gross and net proceeds to the Partnership of $375,000 . The Partnership used the proceeds for general working capital purposes. On March 31, 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 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 (the “October Purchaser”), the Partnership sold and the October Purchaser 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 $350,000,010 . The Partnership used the net proceeds to pay a portion of the consideration for the Western Catarina Midstream acquisition, along with the payment to the October Purchaser of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units. Under the terms of our partnership agreement, commencing with the quarter ended on December 31, 2015, the Class B Preferred Units will receive a quarterly distribution, at the election of the board of directors of our general partner, of 10.0% per annum if paid in full in cash or 12.0% per annum if paid in part cash ( 8.0% per annum) and in part paid-in-kind units ( 4.0% per annum). In the event the Partnership does not raise at least $75,000,000 through the issuance of additional common units prior to September 30, 2016 (with the conversion of the Class A Preferred Units of the Partnership counting toward such amount), the cash portion of the distribution rate will increase by 4.0% per annum until the end of the quarter in which such issuance is consummated. 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. The holders of Class B Preferred Units have the right at any time to request conversion in whole or in part of their Class B Preferred Units at the Conversion Rate, subject to the requirement to convert a minimum of $17,500,000 of Class B Preferred Units. The “Conversion Rate” is equal to the quotient of (i) the aggregate purchase price for the Class B Preferred Units plus accrued and unpaid distributions thereon, divided by (ii) the lesser of (a) the purchase price for the Class B Preferred Units and (b) the volume weighted average price for which common units are issued by the Partnership during the period beginning on the private placement closing date and ending on the date on which the Partnership has issued common units (other than issuances pursuant to the LTIP) in exchange for cash in an aggregate amount equal to at least $75 million. The Class B Preferred Units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands): June 30, December 31, 2016 2015 Mezzanine equity beginning balance $ $ — Private placement of Class B Preferred Units — Discount Amortization of discount Distributions Distributions paid — Total mezzanine equity $ $ Earnings per Unit For the period prior to our conversion, the basic net income per unit was computed from the two-class method by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocated net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) was allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period. Post conversion, 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 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 for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income 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 per unit. Undistributed income 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 Six Months Ended June 30, June 30, June 30, March 6 - June 30 January 1 - March 6 2016 2015 2016 2015 2015 Class A units - Basic and Diluted — — — — Class B Common units - Basic and Diluted — — — — Common units - Basic and Diluted — Weighted Common units - Basic and Diluted At June 30, 2016, we had 328,715 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 six months ended June 30, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ $ Basic and diluted loss per unit $ The following table presents our basic and diluted loss per unit for the three months ended June 30, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ $ Basic and diluted loss per unit $ The following table presents our basic and diluted loss per unit for the period from January 1, 2015 to March 6, 2015 (the date of conversion to a limited partnership) (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net loss to be allocated January 1 - March 6 $ $ $ Basic and diluted loss per unit $ $ The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through June 30, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): Total Common Units Assumed net loss attributable to common unitholders to be allocated March 6 - June 30 $ $ Basic and diluted loss per unit $ Net loss per unit increased significantly for the period from March 6, 2015 through June 30 , 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included a non-cash impairment charge of $ 83.7 million. There was no impairment charge recorded for the period from January 1, 2015 through March 5, 2015.

Reportable Segments

Reportable Segments	6 Months Ended
	Jun. 30, 2016
Reportable Segments [Abstract]
Reportable Segments	15. REPORTABLE SEGMENTS The operating segments, reported separately herein, are best defined as: (1) Exploration and Production and (2) Midstream. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Exploration and Production segment operates to explore for and produce crude oil and natural gas. The Midstream segment operates the gathering, processing and transportation of crude oil, natural gas liquids (“NGLs”) and natural gas. We completed the Western Catarina Midstream Acquisitions during the fourth quarter of 2015. As such, there were no midstream results for the three and six monthes ended June 30, 2015. 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 June 30, 2016 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — Total operating revenues Operating expenses: Lease operating expenses Transportation operating expenses — Cost of sales — Production taxes — General and administrative Unit compensation expense — Depreciation, depletion and amortization Asset impairments — — — Accretion expense Total operating expenses Operating income (loss) $ $ $ Three Months Ended June 30, 2015 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — — — Total operating revenues — Operating expenses: Lease operating expenses — Cost of sales — Production taxes — General and administrative — Unit compensation expense — Gain on sale of assets — Depreciation, depletion and amortization — Asset impairments — Accretion expense — Total operating expenses — Operating loss $ $ — $ Six Months Ended June 30, 2016 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — Total operating revenues Operating expenses: Lease operating expenses Transportation operating expenses — Cost of sales — Production taxes — General and administrative Unit compensation expense — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $ Six Months Ended June 30, 2015 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — — — Total operating revenues — Operating expenses: Lease operating expenses — Cost of sales — Production taxes — General and administrative — Unit compensation expense — Gain on sale of assets — Depreciation, depletion and amortization — Asset impairments — Accretion expense — Total operating expenses — Operating loss $ $ — $ The following table summarizes the total assets by operating segment as of June 30, 2016 and December 31, 2015 (in thousands): June 30, December 31, Segment Assets 2016 2015 Exploration & Production $ $ Midstream Total assets $ $

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	16. SUBSEQUENT EVENTS On June 15, 2016, certain wholly-owned subsidiaries of the Partnership entered into an agreement with Gateway Resources U.S.A., Inc. to sell substantially all of the Partnerships’ operated oil and gas wells, leases and other associated assets and interests in Oklahoma and Kansas (other than those arising under or related to a concession agreement with the Osage Nation) for cash consideration of $7,120 , subject to adjustment for title and environmental defects, effective as of August 1, 2016 (the “Effective Time”). In addition, Gateway Resources U.S.A., Inc. agreed to assume all obligations relating to the assets arising after the Effective Time and all plugging and abandonment costs relating to the assets arising prior to the Effective Time. The Partnership closed the sale of this transaction on July 15, 2016. There is no remaining book value of the assets to be sold. Therefore, the Partnership does not expect to record a loss on the transaction. On July 5, 2016, the Partnership entered into an agreement with SN and SN Midstream, LLC, a wholly-owned subsidiary of SN , to purchase 50% of the issued and outstanding membership interests in Carnero Gathering, LLC for total consideration of approximately $37.0 million, plus the assumption of approximately $7.4 million of remaining capital contribution commitments , of which $1.7 million was paid in July 2016 . In addition, the Partnership is required to pay an earnout based on gas received at the delivery points from SN Catarina, LLC, a wholly-owned subsidiary of SN , and other producers. The membership interests acquired constitute 50% of the outstanding membership interests in Carnero Gathering, LLC, with the other 50% of the membership interests being owned by TPL SouthTex Processing Company LP. Carnero Gathering, LLC is developing and constructing a gas gathering pipeline from an interconnection in Webb County, Texas to interconnection(s) with a gas processing facility being developed and constructed by Carnero Processing, LLC. On July 5, 2016, the Partnership and certain of its subsidiaries entered into that certain Fourth Amendment to Third Amended and Restated Credit Agreement dated as of March 31, 2015 among the Partnership, the guarantors party thereto, each of the lenders party thereto, and Royal Bank of Canada, as administrative agent and collateral agent. Pursuant to the Amendment, the following amendments to the Credit Agreement were made: pricing table was increased; certain covenants were amended to permit the Partnership to own equity interests in joint ventures (including Carnero Gathering, LLC); the Midstream Adjusted EBITDA definition was amended to include in the calculation thereof any distributions received in cash from a joint venture so long as such amount does not exceed 20% of the Midstream Adjusted EBITDA and so long as a “Trigger Event” has not occurred. A “Trigger Event” is defined to be: (i) the ownership and control of less than all of the equity interests initially owned in a joint venture, (ii) the incurrence by the joint venture of any debt other than certain permitted debt, (iii) the disposition by the joint venture of a material portion of its assets, (iv) the incurrence by the joint venture of any liens other than certain permitted liens, (v) the modification of any gathering, compressing, processing, transportation, services or other commercial agreement to which the primary revenues of the joint venture are attributable if the effect of such modification is to reduce in any material respect any minimum committed volumes or minimum committed service level thereunder, or (vi) the joint venture voluntarily filing bankruptcy; a new repayment event was added with respect to any cash or cash equivalents held by the Partnership in excess of $10,000,000 (other than cash set aside to pay distributions in the next 90 days); the title requirement with respect to proved reserves was increased from 80% to 90%; the Partnership is required to pledge its equity interests in any joint venture as collateral under the Credit Agreement; the Partnership, and any of its designees to the board of a joint venture, are restricted from voting on any matter set forth in clauses (ii) through (v) of the definition of “Trigger Event” without the consent of the majority lenders; 10% availability on the entire credit facility (rather than just the RBL component) is required before the Partnership can make distributions; and certain technical revisions were made. On August 10, 2016, the board of directors of the general partner of the Partnership declared cash distributions of $0 . 4183 per common unit and $0.450 per Class B preferred unit for the second quarter of 2016. The distributions are payable on August 31, 2016 to unitholders of record on August 22, 2016 .

Basis Of Presentation And Sum25

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2016
Basis Of Presentation And Summary Of Significant Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation These unaudited condensed consolidated financial statements include the accounts of SPP and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. We conduct our business activities as two operating segments: (1) the exploration and production of oil and natural gas and (2) the midstream business, which includes the Catarina gathering system. 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 the Company and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2015, which was filed with the SEC on March 30, 2016.
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 March 2016, the FASB issued Accounting Standards Update (“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. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued Accounting Standards Update 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. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments,” effective for annual and interim periods beginning after December 15, 2015. ASU 2015-16 eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. During the first quarter of 2016, the Company adopted ASU 2015-16. Adoption of this guidance did not have a material impact on our consolidated financial statements and footnote disclosures. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. In August 2015, the FASB issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” The guidance in ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements. ASU 2015-15 states given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. During the first quarter of 2016, the Company adopted ASU 2015-03 and ASU 2015-15 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of debt issuance costs of approximately $2,091 Decrease in Debt issuance costs (Other Assets) of approximately $2,091 In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. During the first quarter of 2016, the Company adopted ASU 2015-02. Adoption of this guidance did not have a material impact on our consolidated financial statements and footnote disclosures. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” 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 guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.
Reclassifications	Reclassifications Certain reclassifications have been made to the prior period to conform to the current period presentation. These reclassifications had no effect on total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities. In accordance with ASU No. 2015-03 and ASU No. 2015-15, debt issuance costs are to be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. As such, debt issuance costs, net of amortization, at December 31, 2015 of $2.1 million have been reclassified from other assets to other liabilities, effectively eliminating the debt issuance cost line and reducing long-term debt in the balance sheet.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (“NGLs”); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Cash and Cash Equivalents	Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash. Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on. There were no checks-in-transit reported in accounts payable as of June 30, 2016 or December 31, 2015.
Restricted Cash	Restricted Cash As of June 30, 2016 , we had no restricted cash. As of December 31, 2015, we had approximately $ 0 .6 million of restricted cash held in escrow that related to a vendor dispute that remained in the escrow account until the dispute was resolved in March 2016.
Accounts Receivable, Net	Accounts Receivable, Net Our accounts receivable are primarily from purchasers of oil and natural gas, gathering and transportation sales, and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. As of June 30, 2016 and December 31, 2015, we had an allowance for doubtful accounts receivable of $0.1 million and $0.4 million, respectively.

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2016
Business Acquisition [Line Items]
Post-Acquisition Operating Results	Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Three Months Ended Six Months Ended June 30, 2016 June 30, 2016 Revenues $ $ Excess of revenues over direct operating expenses $ $
Eagle Ford [Member]
Business Acquisition [Line Items]
Estimated Values Of Assets Purchased And Liabilities Assumed	Proved developed reserves $ Facilities Fair value of hedges assumed Fair value of assets acquired Asset retirement obligations Ad valorem tax liability Fair value of net assets acquired $
Supplemental Pro Forma Information	Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 Revenues $ $ $ $ Net income (loss) attributable to common unitholders $ $ $ $ Net income (loss) per unit prior to conversion Class A units - Basic and diluted $ — $ — $ — $ Class B units - Basic and diluted $ — $ — $ — $ Net income (loss) per unit after conversion Common units - Basic and diluted $ $ $ $
Western Catarina Midstream [Member]
Business Acquisition [Line Items]
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): Fixed assets $ Contractual customer relationships Purchase of SPP common units from SN Fair value of assets acquired $

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Measurements [Abstract]
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 June 30, 2016 (in thousands): Fair Value Measurements at June 30, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral June 30, 2016 Derivative assets $ — $ $ — $ — $ Derivative liabilities — — — — — Embedded derivative — — Total net assets $ — $ $ $ — $ 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, 2015 (in thousands): Fair Value Measurements at December 31, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2015 Derivative assets $ — $ $ — $ — $ Derivative liabilities — — — — — Embedded derivative — — Total net assets $ — $ $ $ — $
Reconciliation Of Changes In Fair Value Of Embedded Derivative Classified As Level 3	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 six months ended June 30, 2016 and the year ended December 31, 2015 (in thousands): Significant Unobservable Inputs (Level 3) June 30, December 31, 2016 2015 Beginning balance $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Ending balance $ $ Gain (loss) included in earnings related to derivatives still held as of June 30, 2016, and December 31, 2015 $ $

Derivative And Financial Inst28

Derivative And Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative And Financial Instruments [Abstract]
Summary Of Derivative Contracts In Place	Fixed Price Basis Swaps–West Texas Intermediate (WTI) For the Quarter Ended June 30, 2016 (volume in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ Fixed Price Swaps—NYMEX (Henry Hub) For the Quarter Ended June 30, 2016 (volume in Mcfs) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $
Schedule Of Change In Commodity Derivatives Fair Value	June 30, December 31, 2016 2015 Beginning fair value of commodity derivatives $ $ Net gains (losses) on crude oil derivatives Net gains (losses) on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Ending fair value of commodity derivatives $ $
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations	Amount of Gain (Loss) in Income Location of Gain For the Three Months Ended June 30, For the Six Months Ended June 30, Derivative Type in Income 2016 2015 2016 2015 Commodity – Mark-to-Market Oil sales $ $ $ $ Commodity – Mark-to-Market Natural gas sales $ $ $ $
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 quarters ended June 30 , 2016 and the year ended December 31, 2015 (in thousands): June 30, December 31, 2016 2015 Beginning fair value of embedded derivative $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Ending fair value of embedded derivative $ $

Oil And Natural Gas Properties

Oil And Natural Gas Properties (Tables)	6 Months Ended
	Jun. 30, 2016
Oil And Natural Gas Properties [Abstract]
Oil and Natural Gas Properties	June 30, December 31, 2016 2015 Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ $ Unproved property Land Total property costs Materials and supplies Total Less: Accumulated depreciation, depletion, amortization and impairments Oil and natural gas properties and equipment, net $ $
Gathering and Transportation Assets	Gathering and transportation assets consist of the following (in thousands): June 30, December 31, 2016 2015 Gathering and transportation assets Catarina midstream assets $ $ Less: Accumulated depreciation, depletion, amortization Total gathering and transportation assets $ $
Depreciation, Depletion, Amortization and Impairments	Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 DD&A of oil and natural gas-related assets $ $ $ $ DD&A of gathering and transportation related assets — — Total DD&A Asset impairments — Total $ $ $ $

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2016
Asset Retirement Obligation [Abstract]
Reconciliation of Asset Retirement Obligation	June 30, December 31, 2016 2015 Asset retirement obligation, beginning balance $ $ Liabilities added from acquisitions — Liabilities added from drilling — — Sold — Revisions to cost estimates Settlements Accretion expense Asset retirement obligation, ending balance $ $

Intangible Assets (Tables)

Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2016
Intangible Assets
Intangible assets	Intangible assets as of June 30, 2016 and December 31, 2015 are detailed below (in thousands): June 30, December 31, 2016 2015 Beginning balance $ $ Additions — Amortization Ending balance $ $

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2016
Unit-Based Compensation [Abstract]
Schedule Of Units Activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2015 $ Granted Vested Returned/Cancelled Outstanding at June 30, 2016 $

Members' Equity_Partners' Cap33

Members' Equity/Partners' Capital (Tables)	6 Months Ended
	Jun. 30, 2016
Members' Equity/Partners' Capital [Abstract]
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): June 30, December 31, 2016 2015 Mezzanine equity beginning balance $ $ — Private placement of Class B Preferred Units — Discount Amortization of discount Distributions Distributions paid — Total mezzanine equity $ $
Schedule of Weighted Average Basic and Diluted Units Outstanding	Three Months Ended Six Months Ended June 30, June 30, June 30, March 6 - June 30 January 1 - March 6 2016 2015 2016 2015 2015 Class A units - Basic and Diluted — — — — Class B Common units - Basic and Diluted — — — — Common units - Basic and Diluted — Weighted Common units - Basic and Diluted
Income Per Unit Amounts	The following table presents our basic and diluted loss per unit for the six months ended June 30, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ $ Basic and diluted loss per unit $ The following table presents our basic and diluted loss per unit for the three months ended June 30, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ $ Basic and diluted loss per unit $ The following table presents our basic and diluted loss per unit for the period from January 1, 2015 to March 6, 2015 (the date of conversion to a limited partnership) (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net loss to be allocated January 1 - March 6 $ $ $ Basic and diluted loss per unit $ $ The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through June 30, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): Total Common Units Assumed net loss attributable to common unitholders to be allocated March 6 - June 30 $ $ Basic and diluted loss per unit $

Reportable Segments (Tables)

Reportable Segments (Tables)	6 Months Ended
	Jun. 30, 2016
Reportable Segments [Abstract]
Schedule of Segment Information	The following tables set forth our segment information for the periods indicated (in thousands): Three Months Ended June 30, 2016 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — Total operating revenues Operating expenses: Lease operating expenses Transportation operating expenses — Cost of sales — Production taxes — General and administrative Unit compensation expense — Depreciation, depletion and amortization Asset impairments — — — Accretion expense Total operating expenses Operating income (loss) $ $ $ Three Months Ended June 30, 2015 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — — — Total operating revenues — Operating expenses: Lease operating expenses — Cost of sales — Production taxes — General and administrative — Unit compensation expense — Gain on sale of assets — Depreciation, depletion and amortization — Asset impairments — Accretion expense — Total operating expenses — Operating loss $ $ — $ Six Months Ended June 30, 2016 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — Total operating revenues Operating expenses: Lease operating expenses Transportation operating expenses — Cost of sales — Production taxes — General and administrative Unit compensation expense — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $ Six Months Ended June 30, 2015 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — — — Total operating revenues — Operating expenses: Lease operating expenses — Cost of sales — Production taxes — General and administrative — Unit compensation expense — Gain on sale of assets — Depreciation, depletion and amortization — Asset impairments — Accretion expense — Total operating expenses — Operating loss $ $ — $
Summary of Total Assets by Segment	The following table summarizes the total assets by operating segment as of June 30, 2016 and December 31, 2015 (in thousands): June 30, December 31, Segment Assets 2016 2015 Exploration & Production $ $ Midstream Total assets $ $

Organization And Business (Deta

Organization And Business (Details)	6 Months Ended
	Jun. 30, 2016
Organization And Business [Abstract]
Gathering and processing agreement term	15 years

Basis Of Presentation And Sum36

Basis Of Presentation And Summary Of Significant Accounting Policies (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Amortization of debt issuance costs	$ 246	$ 324
Other assets			$ (2,100)
Other liabilities			2,100
Restricted cash			600
Allowance for doubtful accounts	100		400
Accounting Standards Update 2015-03 | Scenario, Adjustment
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Long term debt, net of debt issuance costs			(2,091)
Amortization of debt issuance costs			(2,091)
Checks-In-Transit [Member]
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Cash	$ 0		$ 0

Acquisitions (Details)

Acquisitions (Details) - USD ($)	Oct. 14, 2015	Apr. 15, 2015	Mar. 31, 2015	Jun. 30, 2015
Business Acquisition [Line Items]
Proceeds from preferred units sold				$ 17,375,000
Eagle Ford [Member]
Business Acquisition [Line Items]
Initial purchase price			$ 85,000,000
Cash payment for acquisition			83,400,000
Purchase price			$ 84,299,000
Western Catarina Midstream [Member]
Business Acquisition [Line Items]
Cash payment for acquisition	$ 345,800,000
Repurchase of units (in units)	105,263
Purchase price	$ 345,840,000
Class A Preferred [Member]
Business Acquisition [Line Items]
Price per unit sold		$ 1.60	$ 1.60
Proceeds from preferred units sold		$ 375,000	$ 17,000,000
Class A Preferred [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Shares issued			10,625,000
Price per unit sold			$ 1.60
Proceeds from preferred units sold			$ 17,000,000
Common Units [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Shares issued			105,263
Prior To Stock Split [Member] | Common Units [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Shares issued			1,052,632

Acquisitions (Value Net Assets

Acquisitions (Value Net Assets Acquired) (Details) - USD ($) $ in Thousands	Oct. 14, 2015	Mar. 31, 2015
Eagle Ford [Member]
Business Acquisition [Line Items]
Proved developed reserves		$ 72,889
Facilities		8,002
Fair value of hedges assumed		3,408
Fair value of assets acquired		84,299
Asset retirement obligations		(877)
Ad valorem tax liability		(44)
Fair value of net assets acquired		$ 83,378
Western Catarina Midstream [Member]
Business Acquisition [Line Items]
Fixed assets	$ 142,887
Contractual customer relationships	201,888
Purchase of SPP common units from SN	1,065
Fair value of assets acquired	$ 345,840

Acquisitions (Pro Forma) (Detai

Acquisitions (Pro Forma) (Details) $ / shares in Units, $ in Thousands	Aug. 03, 2015	Jun. 30, 2016USD ($)$ / shares	Jun. 30, 2015USD ($)$ / shares	Jun. 30, 2016USD ($)$ / shares	Jun. 30, 2015USD ($)$ / shares
Business Acquisition [Line Items]
Revenues		$ 12,346	$ 15,375	$ 35,515	$ 41,121
Net income (loss) attributable to common unitholders		(17,630)	$ (23,087)	$ (27,923)	(124,982)
Reverse stock split ratio	0.1
Revenues, actual		16,485			32,157
Excess of revenues over direct operating expenses, actual		$ 12,324			$ 23,822
Class A Unit [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic and diluted (in dollars per unit) | $ / shares					$ (23.87)
Class B Unit [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic and diluted (in dollars per unit) | $ / shares					(18.99)
Common Units [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic and diluted (in dollars per unit) | $ / shares		$ (4.48)	$ (5.39)	$ (7.13)	$ (15.37)
Reverse stock split ratio	0.1

Fair Value Measurements (Detail

Fair Value Measurements (Details) $ in Thousands	Jun. 30, 2016USD ($)derivative	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative	$ (179,885)	$ (193,077)
Number of interest rate derivatives | derivative	0
Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative	$ (179,885)	(193,077)
Total net assets	(165,181)	(162,059)
Fair value of derivative instruments	14,704	31,018
Fair Value, Inputs, Level 2 [Member] | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	14,704	31,018
Total net assets	14,704	31,018
Fair Value, Inputs, Level 3 [Member] | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative	(179,885)	(193,077)
Total net assets	$ (179,885)	$ (193,077)

Fair Value Measurements (Embedd

Fair Value Measurements (Embedded Derivative) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
Fair Value Measurements [Abstract]
Beginning Balance		$ (193,077)
Initial fair value of embedded derivative - bifurcated from mezzanine equity			(183,095)
Gain (loss) on embedded derivative	$ 6,898	13,192	(9,982)
Ending Balance	$ (179,885)	$ (179,885)	$ (193,077)

Derivative And Financial Inst42

Derivative And Financial Instruments (Hedges In Place) (Details)	6 Months Ended
	Jun. 30, 2016$ / bblbbl
Derivative [Line Items]
Average Price | $ / bbl	65.65
West Texas Intermediate 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	106,483
Average Price | $ / bbl	73.95
West Texas Intermediate 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	100,525
Average Price | $ / bbl	74.10
West Texas Intermediate 2016 [Member]
Derivative [Line Items]
Volume (in Bbls)	207,008
Average Price | $ / bbl	74.03
West Texas Intermediate 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	57,953
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	54,554
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	51,570
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	48,926
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 [Member]
Derivative [Line Items]
Volume (in Bbls)	213,003
Average Price | $ / bbl	64.80
West Texas Intermediate 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	56,798
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	54,197
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	51,851
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	49,709
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 [Member]
Derivative [Line Items]
Volume (in Bbls)	212,555
Average Price | $ / bbl	65.40
West Texas Intermediate 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	52,760
Average Price | $ / bbl	65.65
West Texas Intermediate 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	50,784
Average Price | $ / bbl	65.65
West Texas Intermediate 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	48,960
West Texas Intermediate 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	47,264
Average Price | $ / bbl	65.65
West Texas Intermediate 2019 [Member]
Derivative [Line Items]
Volume (in Bbls)	199,768
Average Price | $ / bbl	65.65
West Texas Intermediate [Member]
Derivative [Line Items]
Volume (in Bbls)	832,334
NYMEX 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	998,394
Average Price | $ / bbl	4.14
NYMEX 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	963,327
Average Price | $ / bbl	4.14
NYMEX 2016 [Member]
Derivative [Line Items]
Volume (in Bbls)	1,961,721
Average Price | $ / bbl	4.14
NYMEX 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	80,563
Average Price | $ / bbl	3.52
NYMEX 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	75,829
Average Price | $ / bbl	3.52
NYMEX 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	71,672
Average Price | $ / bbl	3.52
NYMEX 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	67,984
Average Price | $ / bbl	3.52
NYMEX 2017 [Member]
Derivative [Line Items]
Volume (in Bbls)	296,048
Average Price | $ / bbl	3.52
NYMEX 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	79,042
Average Price | $ / bbl	3.58
NYMEX 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	75,404
Average Price | $ / bbl	3.58
NYMEX 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	72,115
Average Price | $ / bbl	3.58
NYMEX 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	69,122
Average Price | $ / bbl	3.58
NYMEX 2018 [Member]
Derivative [Line Items]
Volume (in Bbls)	295,683
Average Price | $ / bbl	3.58
NYMEX 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	73,432
Average Price | $ / bbl	3.62
NYMEX 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	70,648
Average Price | $ / bbl	3.62
NYMEX 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	68,088
Average Price | $ / bbl	3.62
NYMEX 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	65,720
Average Price | $ / bbl	3.62
NYMEX 2019 [Member]
Derivative [Line Items]
Volume (in Bbls)	277,888
Average Price | $ / bbl	3.62
NYMEX [Member]
Derivative [Line Items]
Volume (in Bbls)	2,831,340

Derivative And Financial Inst43

Derivative And Financial Instruments (Changes In Fair Value) (Details) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)item	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ (7,726)	$ (5,897)	$ (3,736)	$ (1,064)
Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives			31,018	22,829	$ 22,829
Ending fair value of commodity derivatives	14,704		$ 14,704		31,018
Number of counterparties | item			3
Oil [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives			$ (3,568)		22,410
Net settlements on derivative contracts			(8,052)		(13,191)
Oil [Member] | Oil And Liquids Sales [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	(6,260)	(5,555)	(3,568)	(2,912)
Natural Gas [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives			(168)		6,148
Net settlements on derivative contracts			(4,526)		$ (7,178)
Natural Gas [Member] | Natural Gas Sales [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ (1,466)	$ (342)	$ (168)	$ 1,848

Derivative And Financial Inst44

Derivative And Financial Instruments (Eagle Ford) (Details) - Eagle Ford [Member] $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Derivative [Line Items]
Oil and natural gas production, 2016	90.00%
Oil and natural gas production, 2017	85.00%
Oil and natural gas production, 2018	85.00%
Oil and natural gas production, 2019	80.00%
Fair value of derivative instruments	$ 8.9

Derivative And Financial Inst45

Derivative And Financial Instruments (Embedded Derivative) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
Derivative And Financial Instruments [Abstract]
Beginning Balance		$ (193,077)
Initial fair value of embedded derivative - bifurcated from mezzanine equity			(183,095)
Gain (loss) on embedded derivative	$ 6,898	13,192	(9,982)
Ending Balance	$ (179,885)	$ (179,885)	$ (193,077)

Long-Term Debt (Details)

Long-Term Debt (Details)	6 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)	May 19, 2016USD ($)
Line of Credit Facility [Line Items]
Amortization of debt issuance costs	$ 246,000	$ 324,000
Unamortized debt issue costs	1,900,000		$ 2,100,000
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	500,000,000
Sub-limit which may be used for issuance of letters of credit	$ 15,000,000
Borrowing base amount				$ 200,000,000
Exceeding of reserve-based credit facility over borrowing base (as a percent)	90.00%
Credit Agreement [Member] | Second full quarter after Catarina acquisition
Line of Credit Facility [Line Items]
Borrowing base multiplier	4.75
Credit Agreement [Member] | Thereafter
Line of Credit Facility [Line Items]
Borrowing base multiplier	4.5
Minimum | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base	0.375%
Consolidated current asset ratio	1
Required interest coverage ratio	2.5
Minimum | Credit Agreement [Member] | Scenario One [Member]
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5
Minimum | Credit Agreement [Member] | Scenario Two [Member]
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4
Minimum | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Variable interest rate	1.75%
Minimum | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Variable interest rate	0.75%
Maximum | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base	0.50%
Maximum | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Variable interest rate	2.75%
Maximum | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Variable interest rate	1.75%
Accounting Standards Update 2015-03 | Scenario, Adjustment
Line of Credit Facility [Line Items]
Long term debt, net of debt issuance costs			(2,091,000)
Amortization of debt issuance costs			$ (2,091,000)

Oil And Natural Gas Propertie47

Oil And Natural Gas Properties (Properties) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Oil And Natural Gas Properties [Abstract]
Proved property	$ 731,435	$ 731,548
Unproved property	41	39
Land	501	501
Total property costs	731,977	732,088
Materials and supplies	1,056	1,056
Total	733,033	733,144
Less: Accumulated depreciation, depletion, amortization and impairments	(657,259)	(652,167)
Oil and natural gas properties and equipment, net	$ 75,774	$ 80,977

Oil and Natural Gas Propertie48

Oil and Natural Gas Properties (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Gathering and transportation assets	$ 147,695	$ 147,479
Less: Accumulated depreciation, depletion, amortization and impairments	(657,259)	(652,167)
Midstream [Member]
Property, Plant and Equipment [Line Items]
Less: Accumulated depreciation, depletion, amortization and impairments	(4,840)	(1,402)
Total gathering and transportation assets	142,855	146,077
Midstream [Member] | Western Catarina Midstream [Member]
Property, Plant and Equipment [Line Items]
Gathering and transportation assets	$ 147,695	$ 147,479

Oil and Natural Gas Propertie49

Oil and Natural Gas Properties (DDA and Impairments) (Details) - USD ($) $ in Thousands	Mar. 05, 2015	Feb. 28, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
DD&A					$ 7,262	$ 6,011
Asset impairments	$ 0	$ 0		$ 862	1,309	83,727
Total			$ 2,671	3,941	7,709	89,926
Proved property			731,435		731,435		$ 731,548
Exploration and dry hole costs					$ 0	0
Gathering Facilities [Member]
Property, Plant and Equipment [Line Items]
Useful lives					36 years
Oil and Natural Gas-Related Assets [Member]
Property, Plant and Equipment [Line Items]
DD&A			942	3,079	$ 2,962	6,199
Gathering and Transportation Related Assets [Member]
Property, Plant and Equipment [Line Items]
DD&A			1,729		$ 3,438
Gathering and Transportation Related Assets [Member] | Minimum
Property, Plant and Equipment [Line Items]
Useful lives					3 years
Gathering and Transportation Related Assets [Member] | Maximum
Property, Plant and Equipment [Line Items]
Useful lives					15 years
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets [Member]
Property, Plant and Equipment [Line Items]
DD&A			2,671	$ 3,079	$ 6,400	$ 6,199
Texas And Louisiana Oil And Natural Gas Fields [Member]
Property, Plant and Equipment [Line Items]
Proved property			$ 75,800		$ 75,800

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset retirement obligation, beginning balance			$ 20,364	$ 17,031	$ 17,031
Liabilities added from acquisitions					3,634
Sold					(58)
Revisions to cost estimates			(1,393)		(1,156)
Settlements			(86)		(186)
Accretion expense	$ 315	$ 264	630	$ 517	1,099
Asset retirement obligation, ending balance	$ 19,515		$ 19,515		$ 20,364

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2016USD ($)a	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)
Finite-Lived Intangible Assets [Line Items]
Agreement term	15 years
Amortization expense	$ 6,917	$ 188
Balance	199,741	$ 1,033	$ 1,033
Additions			201,888
Amortization	(6,917)		(3,180)
Balance	$ 192,824		$ 199,741
Customer Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Agreement term	15 years
Dedicated acreage | a	35,000
Useful life	15 years
Balance	$ 192,300
Marketing Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Useful life	10 years
Balance	$ 500

Related Party Transactions (Det

Related Party Transactions (Details)	Oct. 14, 2015USD ($)aMcfbbl	Mar. 31, 2015USD ($)shares	Oct. 31, 2015shares	Jun. 30, 2016USD ($)shares	Jun. 30, 2015USD ($)	Jul. 05, 2016	Dec. 31, 2015USD ($)shares	Sep. 30, 2015USD ($)	Aug. 04, 2015shares	Aug. 03, 2015shares
Related Party Transaction [Line Items]
Agreement term				15 years
Related parties, net receivable				$ 7,400,000			$ 1,500,000
Related parties, net payable				$ 3,700,000			$ 1,000,000
Cash payment for acquisition, net					$ 81,378,000
SP Holdings [Member]
Related Party Transaction [Line Items]
Percent of value of properties held used to compute quarterly fee				0.375%
Administrative fee paid				$ 3,000,000	$ 2,400,000
Maximum asset acquisition, disposition and financing fee				2.00%
Agreement term				10 years
Services Agreement renewal term				10 years
Prepaid administrative fee								$ 500,000
Carnero Gathering LLC, Joint Venture | Subsequent Event
Related Party Transaction [Line Items]
Ownership interest (as a percent)						50.00%
Eagle Ford [Member]
Related Party Transaction [Line Items]
Initial purchase price		$ 85,000,000
Cash payment for acquisition		83,400,000
Eagle Ford [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Initial purchase price		85,000,000
Closing adjustments		1,400,000
Cash payment for acquisition, net		$ 81,600,000
Western Catarina Midstream [Member]
Related Party Transaction [Line Items]
Agreement term	15 years
Acres dedicated for gathering | a	35,000
Gathering Agreement delivery commitment period	5 years
Proceeds from gathering and processing agreement				$ 23,200,000
Cash payment for acquisition	$ 345,800,000
Western Catarina Midstream [Member] | Oil [Member]
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | bbl	10,200
Western Catarina Midstream [Member] | Natural Gas [Member]
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | Mcf	142,000
Class A Preferred [Member] | Eagle Ford [Member]
Related Party Transaction [Line Items]
Business acquisition, units issued | shares		10,625,000
Common Units [Member]
Related Party Transaction [Line Items]
Units, outstanding | shares				4,279,517			3,240,812		3,149,551	31,495,506
Common Units [Member] | Eagle Ford [Member]
Related Party Transaction [Line Items]
Business acquisition, units issued | shares		105,263
Common Units [Member] | Eagle Ford [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Business acquisition, units issued | shares		105,263
Business acquisition, value of units		$ 2,000,000
Shares repurchased | shares			105,263

Unit-Based Compensation (Detail

Unit-Based Compensation (Details)	Dec. 01, 2015shares	Aug. 03, 2015	Mar. 31, 2015shares	Jun. 30, 2016shares	Dec. 31, 2015shares	Dec. 31, 2015shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Reverse stock split ratio		0.1
Shares approved for grant	335,715
Vesting period	3 years
Common Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Reverse stock split ratio		0.1
Number of Restricted Units, Withheld for taxes				12,227	32,269
Restricted Stock Units (RSUs) [Member] | Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted						34,693
Restricted Stock Units (RSUs) [Member] | Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted			102,564
Number of Restricted Units, Vested			76,923
Number of Restricted Units, Withheld for taxes			32,269
Prior To Stock Split [Member] | Restricted Stock Units (RSUs) [Member] | Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted						346,925
Prior To Stock Split [Member] | Restricted Stock Units (RSUs) [Member] | Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted			1,025,641
Number of Restricted Units, Vested			769,231
Number of Restricted Units, Withheld for taxes			322,692

Unit-Based Compensation (Restri

Unit-Based Compensation (Restricted Units Activity) (Details)	6 Months Ended
	Jun. 30, 2016$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	328,715
LTIP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units available for issuance	213,273
Restricted Stock Units (RSUs) [Member] | LTIP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	361,357
Number of Restricted Units, Granted	(67,627)
Number of Restricted Units, Vested	(86,041)
Number of Restricted Units, Returned/Cancelled	(14,227)
Number of Restricted Units, Outstanding	328,716
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ / shares	$ 14.18
Weighted Averaged Grant Date Fair Value Per Unit, Granted | $ / shares	10.35
Weighted Averaged Grant Date Fair Value Per Unit, Vested | $ / shares	11.54
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled | $ / shares	15.81
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ / shares	$ 14.01

Distributions To Unitholders (D

Distributions To Unitholders (Details)	Aug. 10, 2016$ / shares	May 10, 2016$ / shares	Feb. 29, 2016$ / shares	Feb. 09, 2016$ / shares	Nov. 30, 2015$ / shares	Jun. 30, 2016shares	Jun. 30, 2015$ / shares	Dec. 31, 2009$ / shares	Dec. 31, 2015shares	Dec. 31, 2014$ / shares	Mar. 31, 2016
Paid-in-kind units distributed | shares									549,756
Class A preferred units converted to common shares, conversion ratio						1					1
Common Units [Member]
Distribution paid per unit			$ 0.406		$ 0.400		$ 0	$ 0		$ 0
Distribution declared per unit		$ 0.4121		$ 0.406
Common Units [Member] | Subsequent Event
Distribution declared per unit	$ 0.4183
Class A Preferred [Member]
Paid-in-kind units distributed | shares						0
Distributions declared as a percentage				2.50%
Distributions paid as a percentage			2.50%
Class B Preferred [Member]
Distribution paid per unit			$ 0.3815
Distribution declared per unit		$ 0.450		$ 0.3815
Class B Preferred [Member] | Subsequent Event
Distribution declared per unit	$ 0.450

Members' Equity_Partners' Cap56

Members' Equity/Partners' Capital (Details)	Oct. 14, 2015USD ($)$ / sharesshares	Aug. 03, 2015$ / sharesshares	Apr. 15, 2015USD ($)$ / sharesshares	Mar. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2015shares	Jun. 30, 2016USD ($)shares	Jun. 30, 2015USD ($)	Dec. 31, 2015USD ($)shares	Mar. 31, 2016	Aug. 04, 2015$ / sharesshares	Apr. 30, 2015USD ($)
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding | shares					19,444,445	19,444,445		19,444,445
Class A preferred units converted to common shares, conversion ratio						1			1
Restricted unvested common units granted and outstanding | shares						328,715
Issuance of common units, value						$ 771,000		$ 193,000
Reverse stock split ratio		0.1
Proceeds from preferred units sold							$ 17,375,000
Proceeds from common units sold							$ 52,000
LTIP [Member]
Limited Partners' Capital Account [Line Items]
Common units available under incentive plan | shares						213,273
Class A Preferred [Member]
Limited Partners' Capital Account [Line Items]
Class A preferred units, outstanding | shares					11,409,131	0		11,409,131
Units sold (in units) | shares			234,375	10,625,000
Price per unit sold | $ / shares			$ 1.60	$ 1.60
Proceeds from preferred units sold			$ 375,000	$ 17,000,000
Increase in distribution rate						4.00%
Class B Preferred [Member]
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding | shares						19,444,445
Units sold (in units) | shares	19,444,445
Price per unit sold | $ / shares	$ 18
Proceeds from preferred units sold	$ 350,000,010
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%
Common Units [Member]
Limited Partners' Capital Account [Line Items]
Units, outstanding | shares		31,495,506			3,240,812	4,279,517		3,240,812		3,149,551
Common units sales agreement, value of common units allocated											$ 100,000,000
Issuance of common units, value						$ 771,000		$ 193,000
Reverse stock split ratio		0.1
Units, issued | shares		31,495,506			3,240,812	4,279,517		3,240,812		3,149,551
Market price | $ / shares		$ 1.55								$ 15.50
Minimum | Class A Preferred [Member]
Limited Partners' Capital Account [Line Items]
Proceeds from common units sold						$ 75,000,000
Minimum | Class B Preferred [Member]
Limited Partners' Capital Account [Line Items]
Preferred unit conversion, amount						17,500,000
Cash from conversion						$ 75,000,000

Members Equity Partners Capital

Members Equity Partners Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Dec. 31, 2015
Mezzanine equity beginning balance	$ 172,111
Distributions	16,168
Total mezzanine equity	186,264	$ 172,111
Class B Preferred [Member]
Mezzanine equity beginning balance	172,111
Private placement of Class B Preferred Units		350,000
Discount	(87)	(191,901)
Amortization of discount	12,908	6,594
Distributions	17,500	7,418
Distributions paid	(16,168)
Total mezzanine equity	$ 186,264	$ 172,111

Members' Equity_Partners' Cap58

Members' Equity/Partners' Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 05, 2015	Mar. 31, 2015	Mar. 05, 2015	Feb. 28, 2015	Jun. 30, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Assumed net income (loss)		$ (99,928)	$ (923)		$ (17,207)	$ (10,865)			$ (27,947)	$ (100,851)
Asset impairments	$ 0			$ 0		$ 862			$ 1,309	$ 83,727
Class A Unit [Member]
Weighted Average Units Outstanding - Basic and diluted										48,451
Assumed net income (loss)			$ (18)
Net loss per unit - Basic and diluted			$ (0.38)							$ (0.38)
Class B Unit [Member]
Weighted Average Units Outstanding - Basic and diluted										2,879,163
Assumed net income (loss)			$ (905)
Net loss per unit - Basic and diluted			$ (0.31)							$ (0.31)
Common Units [Member]
Weighted Average Units Outstanding - Basic and diluted					3,935,297	3,113,428			3,333,482	3,087,431
Assumed net income (loss)					$ (17,207)				$ (27,947)
Net loss per unit - Basic and diluted		$ (3.23)			$ (4.37)	$ (3.49)			$ (8.38)	$ (32.37)
Prior To Stock Split [Member]
Weighted Average Units Outstanding - Basic and diluted		3,113,428	3,333,482				2,927,613	3,087,431	3,935,297
Prior To Stock Split [Member] | Class A Unit [Member]
Weighted Average Units Outstanding - Basic and diluted							48,451
Prior To Stock Split [Member] | Class B Unit [Member]
Weighted Average Units Outstanding - Basic and diluted							2,879,163
Prior To Stock Split [Member] | Common Units [Member]
Weighted Average Units Outstanding - Basic and diluted		3,113,428	3,333,482					3,087,431	3,935,297

Reportable Segments (Segment In

Reportable Segments (Segment Information) (Details) - USD ($) $ in Thousands	Mar. 05, 2015	Feb. 28, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Operating Revenues
Natural gas sales			$ 600	$ 3,642	$ 4,275	$ 10,216
Oil sales			(2,756)	639	2,587	5,603
Natural gas liquid sales			244	500	520	886
Gathering and transportation sales			14,258		28,133
Total revenues			12,346	4,781	35,515	16,705
Operating expenses:
Lease operating expenses			4,178	5,358	9,151	10,258
Transportation operating expenses			3,014		6,068
Cost of sales			63	125	193	330
Production taxes			326	583	547	953
General and administrative			4,978	3,351	10,697	10,906
Unit compensation expense			1,091	395	1,529	2,387
Gain on sale of assets				(54)		(113)
Depreciation, depletion and amortization			6,129	3,079	13,317	6,199
Asset impairments	$ 0	$ 0		862	1,309	83,727
Accretion expense			315	264	630	517	$ 1,099
Total operating expenses			20,094	13,963	43,441	115,164
Operating income (loss)			(7,748)	(9,182)	(7,926)	(98,459)
Upstream [Member]
Operating Revenues
Natural gas sales			600	3,642	4,275	10,216
Oil sales			(2,756)	639	2,587	5,603
Natural gas liquid sales			244	500	520	886
Total revenues			(1,912)	4,781	7,382	16,705
Operating expenses:
Lease operating expenses			3,904	5,358	8,780	10,258
Cost of sales			63	125	193	330
Production taxes			326	583	547	953
General and administrative			3,550	3,351	7,984	10,906
Unit compensation expense			1,091	395	1,529	2,387
Gain on sale of assets				(54)		(113)
Depreciation, depletion and amortization			1,036	3,079	3,149	6,199
Asset impairments				862	1,309	83,727
Accretion expense			253	264	507	517
Total operating expenses			10,223	13,963	23,998	115,164
Operating income (loss)			(12,135)	$ (9,182)	(16,616)	$ (98,459)
Midstream [Member]
Operating Revenues
Gathering and transportation sales			14,258		28,133
Total revenues			14,258		28,133
Operating expenses:
Lease operating expenses			274		371
Transportation operating expenses			3,014		6,068
General and administrative			1,428		2,713
Depreciation, depletion and amortization			5,093		10,168
Accretion expense			62		123
Total operating expenses			9,871		19,443
Operating income (loss)			$ 4,387		$ 8,690

Reportable Segments (Assets by

Reportable Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 440,057	$ 471,300
Upstream [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	59,920	118,083
Midstream [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 380,137	$ 353,217

Subsequent Events (Details)

Subsequent Events (Details) - USD ($)	Aug. 10, 2016	Jul. 05, 2016	Jun. 15, 2016	May 10, 2016	Feb. 09, 2016	Jul. 31, 2016
Common Units [Member]
Subsequent Event [Line Items]
Distribution declared per unit				$ 0.4121	$ 0.406
Class B Preferred [Member]
Subsequent Event [Line Items]
Distribution declared per unit				$ 0.450	$ 0.3815
Subsequent Event | Common Units [Member]
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.4183
Subsequent Event | Class B Preferred [Member]
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.450
Fourth Amendment Credit Facility | Subsequent Event
Subsequent Event [Line Items]
Threshold limit for distribution received in cash as percentage of Midstream Adjusted EBITDA		20.00%
Repayment in excess of cash and cash equivalents when partnership voluntarily filing bankruptcy		$ 10,000,000
Period to pay distributions		90 days
Percentage on credit facility required to make distributions and technical revisions		10.00%
Fourth Amendment Credit Facility | Subsequent Event | Minimum
Subsequent Event [Line Items]
Percentage of proved reserves requirement		80.00%
Fourth Amendment Credit Facility | Subsequent Event | Maximum
Subsequent Event [Line Items]
Percentage of proved reserves requirement		90.00%
Gateway Resources U.S.A., Inc.
Subsequent Event [Line Items]
Proceeds from divestiture of business			$ 7,120,000
Carnero Gathering LLC, Joint Venture | Subsequent Event
Subsequent Event [Line Items]
Payments to Acquire Interest in Joint Venture		$ 37,000,000
Assumption of capital commitments in joint venture		$ 7,400,000
Payments of capital commitments from joint venture						$ 1,700,000
Ownership interest (as a percent)		50.00%
TPL South Tex Processing Company LP | Subsequent Event
Subsequent Event [Line Items]
Ownership interest (as a percent)		50.00%