Evolve Transition Infrastructure (SNMP) 10-Q 13 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 13, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
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		3,048,283
Entity Current Reporting Status	Yes

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues
Natural gas sales		$ 5,730	$ 9,153	$ 15,946	$ 21,752
Oil sales		19,501	11,402	25,104	21,784
Natural gas liquid sales		394	841	1,280	1,690
Total revenues		25,625	21,396	42,330	45,226
Operating expenses:
Lease operating expenses		5,194	5,296	15,452	15,598
Cost of sales		139	404	469	1,198
Production taxes		443	796	1,396	2,563
General and administrative		7,376	3,780	20,669	12,942
(Gain) loss on sale of assets		2		(111)	(23)
Depreciation, depletion and amortization		2,851	4,836	9,050	13,206
Asset impairments		937	43	84,664	237
Accretion expense		265	151	782	451
Total expenses		17,207	15,306	132,371	46,172
Other expenses (income)
Interest expense		672	511	2,440	1,569
Other expenses (income)		(52)	(76)	48	(220)
Total other expenses		620	435	2,488	1,349
Total expenses		17,827	15,741	134,859	47,521
Income (loss) before income taxes		7,798	5,655	(92,529)	(2,295)
Income tax expense		3		3
Net income (loss)		7,795	5,655	(92,532)	(2,295)
Less:
Preferred unit paid-in-kind distributions		(445)		(969)
Net loss attributable to common unitholders		$ 7,350	5,655	$ (93,501)	(2,295)
Income (loss) per unit
Net income (loss) per unit, basic (in dollars per unit)	[1]	$ 2.33		$ (29.83)
Net income (loss) per unit, diluted (in dollars per unit)		$ 0.55		$ (29.83)
Weighted average units outstanding, basic		3,124,004		3,103,608
Weighted average units outstanding, diluted	[1]	14,074,856		3,103,608
Class A Unit [Member]
Less:
Net loss attributable to common unitholders			$ 113		$ (46)
Income (loss) per unit
Net income (loss) per unit, basic (in dollars per unit)	[1]		$ 2.33	$ (0.38)	$ (0.54)
Net income (loss) per unit, diluted (in dollars per unit)	[1]		$ 2.33	$ (0.38)	$ (0.54)
Weighted average units outstanding, basic	[1]		48,451	48,451	85,720
Weighted average units outstanding, diluted	[1]		48,451	48,451	85,720
Class B Unit [Member]
Less:
Net loss attributable to common unitholders			$ 5,542		$ (2,249)
Income (loss) per unit
Net income (loss) per unit, basic (in dollars per unit)	[1]		$ 1.94	$ (0.31)	$ (0.79)
Net income (loss) per unit, diluted (in dollars per unit)	[1]		$ 1.93	$ (0.31)	$ (0.79)
Weighted average units outstanding, basic	[1]		2,855,257	2,879,163	2,835,859
Weighted average units outstanding, diluted	[1]		2,866,088	2,879,163	2,835,859
[1]	(1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.

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	Sep. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 8,963	$ 4,238
Restricted cash	600	1,748
Accounts receivable	3,103	3,901
Accounts receivable - related entities	681	959
Prepaid expenses	1,108	1,783
Fair value of derivative instruments	17,784	14,671
Total current assets	32,239	27,300
Oil and natural gas properties and related equipment (successful efforts method)
Oil and natural gas properties, equipment and facilities	732,766	651,493
Material and supplies	1,056	1,056
Less accumulated depreciation, depletion, amortization, accretion and impairments	(610,279)	(517,239)
Oil and natural gas properties and equipment, net	123,543	135,310
Other assets
Debt issuance costs	1,571	689
Fair value of derivative instruments	10,124	8,158
Other non-current assets	2,302	1,790
Total assets	169,779	173,247
Current liabilities
Accounts payable and accrued liabilities	9,663	5,759
Royalties payable	680	1,134
Total current liabilities	10,343	6,893
Other liabilities
Asset retirement obligation	18,593	17,031
Debt (See Note 6)	106,000	42,500
Total other liabilities	124,593	59,531
Total liabilities	$ 134,936	$ 66,424
Commitments and contingencies (See Note 9)
Members' equity / Partners' capital
Common units	$ 19,017
Class A preferred units	15,826
Total members' equity/partners' capital	34,843	$ 106,823
Total liabilities and members' equity/partners' capital	169,779	173,247
Class A Unit [Member]
Members' equity / Partners' capital
Common units		1,930
Total members' equity/partners' capital		1,930
Class B Unit [Member]
Members' equity / Partners' capital
Common units		104,893
Total members' equity/partners' capital		$ 104,893
Common Units [Member]
Members' equity / Partners' capital
Total members' equity/partners' capital	$ 19,017

Condensed Consolidated Balance5

Condensed Consolidated Balance Sheets (Parenthetical)	Sep. 30, 2015shares	Dec. 31, 2014shares
Class A Unit [Member]
Common units, issued	0	48,451	[1]
Common units, outstanding	0
Class B Unit [Member]
Common units, issued	0	2,879,258	[1]
Common units, outstanding	0
Class A Preferred [Member]
Preferred units, issued	11,130,855	0
Preferred units, outstanding	11,130,855	0
Common Units [Member]
Common units, issued		0
Common units, outstanding	3,149,693
[1]	(1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.

Condensed Consolidated Stateme6

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities:
Net loss	$ (92,532)	$ (2,295)
Adjustments to reconcile net loss to cash provided by operating activities
Depreciation, depletion and amortization	9,050	13,206
Asset impairments	84,664	237
Amortization of debt issuance costs	413	199
Accretion expense	782	451
Equity earnings in affiliate	(2)	(147)
Gain from disposition of property and equipment	(111)	(23)
Bad debt expense	122	80
Total mark-to-market gains (losses) on commodity derivative contracts	(16,256)	1,134
Cash mark-to-market settlements on commodity derivative contracts	13,441	4,184
Unit-based compensation programs	2,463	1,216
Changes in Operating Assets and Liabilities:
(Increase) decrease in accounts receivable	1,820	(408)
Decrease in accounts receivable - related entities	278	49
Decrease in prepaid expenses	675	869
(Increase) decrease in other assets	(867)	3
Increase (decrease) in accounts payable/accrued liabilities	5,195	(4,603)
Decrease in royalties payable	(454)	(70)
Decrease in other liabilities		(1,398)
Net cash provided by operating activities	8,681	12,684
Cash flows from investing activities:
Cash paid for acquisitions	(81,378)	(1,351)
Development of natural gas properties	(1,313)	(5,025)
Proceeds from sale of assets	470	58
Distributions from equity affiliate	60	180
Net cash used in investing activities	(82,161)	(6,138)
Cash flows from financing activities:
Proceeds from issuance of preferred units	17,375
Payments for offering costs	(810)
Proceeds from issuance of debt	106,000	5,750
Repayment of debt	(42,500)	(4,500)
Issuance of common units	52
Repurchase of Class A, Class C and Class D interests		(2,468)
Units tendered by employees for tax withholdings	(618)	(415)
Debt issuance costs	(1,294)	(136)
Net cash provided by (used in) financing activities	78,205	(1,769)
Net increase in cash and cash equivalents	4,725	4,777
Cash and cash equivalents, beginning of period	4,238	4,894
Cash and cash equivalents, end of period	8,963	9,671
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	(149)	(219)
Acquisitions of oil and natural gas properties in exchange for common units	2,000
Cash paid during the period for interest	$ (1,973)	$ (1,379)

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
Partners' Capital, Beginning Balance at Dec. 31, 2014		$ 1,930	$ 104,893				$ 106,823
Beginning Balance (in shares) at Dec. 31, 2014	[1]	48,451	2,879,258
Units tendered by employees for tax withholding			$ (21)				(21)
Units tendered by employees for tax withholding (in shares)	[1]		(1,557)
Net income (loss)		$ (18)	$ (905)				(923)
Partners' Capital, Ending Balance at Mar. 31, 2015		$ 1,912	$ 103,967				105,879
Ending Balance (in shares) at Mar. 31, 2015	[1]	48,451	2,877,701
Partners' Capital, Beginning Balance at Dec. 31, 2014		$ 1,930	$ 104,893				106,823
Beginning Balance (in shares) at Dec. 31, 2014	[1]	48,451	2,879,258
Net income (loss)							(92,532)
Partners' Capital, Ending Balance at Sep. 30, 2015				$ 15,826	$ 19,017		$ 34,843
Ending Balance (in shares) at Sep. 30, 2015				11,130,855	3,149,693	[1]
[1]	(1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.

Condensed Consolidated Stateme8

Condensed Consolidated Statements Of Changes In Members' Equity/Partners' Capital (Parenthetical) $ in Thousands	Aug. 03, 2015	Sep. 30, 2015USD ($)
Condensed Consolidated Statements Of Changes In Members' Equity/Partners' Capital [Abstract]
Payments of Stock Issuance Costs		$ 810
Reverse stock split ratio	0.1

Organization And Basis Of Prese

Organization And Basis Of Presentation	9 Months Ended
	Sep. 30, 2015
Organization And Basis Of Presentation [Abstract]
Organization And Basis Of Presentation	1. ORGANIZATION AND BASIS OF PRESENTATION Organization Sanchez Production Partners LP, a Delaware limited partnership (“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. We have also commenced a process to sell our oil and gas properties in the Mid-Continent region. As a result of the acquisition of midstream assets from SN and the proposed 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 will come from the long-term, fee-based gathering and processing agreement with SN rather than from oil and natural gas production. 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 operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties. 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, 2014, which was filed with the SEC on March 5, 2015. 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. 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 and an immaterial effect on total assets and total liabilities. 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 April 2015, FASB issued Accounting Standards Update (“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. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. In February 2015, the FASB issued an 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. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, but we do not expect the impact to be material. 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. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	2. SUMMARY OF 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, 2014. Cash 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 at September 30, 2015 and December 31, 2014. Restricted Cash Restricted cash, as of September 30, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of September 30, 2015 is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved. Accounts Receivable, Net Our accounts receivable are primarily from purchasers of oil and natural gas 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. At September 30, 2015 and December 31, 2014, we had an allowance for doubtful accounts receivable of $0.4 million and $0.2 million, respectively.

Acquisitions And Divestitures

Acquisitions And Divestitures	9 Months Ended
	Sep. 30, 2015
Acquisitions And Divestitures [Abstract]
Acquisitions And Divestitures	3. ACQUISITIONS AND DIVESTITURES 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 which 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 reverse unit split) to SN, borrowings under the Partnership’s Credit Agreement (as defined in Note 7, “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. Pro Forma Operating Results The following unaudited pro forma combined financial information for the three and nine months ended September 30, 2015 and 2014 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, 2014. 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 Class A Preferred Units to finance a portion of the Eagle Ford acquisition, and the related adjustments to preferred paid-in-kind distributions. · 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 Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Revenues $ $ $ $ Net income (loss) attributable to common unitholders $ $ $ $ Net income (loss) per unit prior to conversion Class A units - Basic and diluted (1) $ — $ $ $ Class B units - Basic (1) $ — $ $ $ Class B units - Diluted (1) $ — $ $ $ Net income (loss) per unit after conversion Common units - Basic (1) $ $ — $ $ — Common units - Diluted (1) $ $ — $ $ — (1) Amounts adjusted for 1 -for-10 reverse split completed August 3, 2015. See Note 13. 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 nine months ended September 30, 2015, for the Eagle Ford acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Three Nine Months Ended Months Ended September 30, 2015 September 30, 2015 Revenues $ $ Excess of revenues over direct operating expenses $ $

Fair Value Messurements

Fair Value Messurements	9 Months Ended
	Sep. 30, 2015
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 September 30, 2015 (in thousands): Fair Value Measurements at September 30, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral September 30, 2015 Derivative assets $ — $ $ — $ — $ 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, 2014 (in thousands): Fair Value Measurements at December 31, 2014 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2014 Derivative assets $ — $ $ — $ $ Derivative liabilities — — — Total net assets $ — $ $ — $ — $ As of September 30, 2015 and December 31, 2014, 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 and Divestitures.” A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 8, ‘‘Asset Retirement Obligations.’’ 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 7, “Long-Term Debt.” Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate derivatives as of September 30, 2015. 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.

Derivative And Financial Instru

Derivative And Financial Instruments	9 Months Ended
	Sep. 30, 2015
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 September 30, 2015, 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 (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 2015 $ $ 2016 $ $ $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ Fixed Price Swaps—NYMEX (Henry Hub) For the Quarter Ended (in MMBtu) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2015 $ $ 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 nine months ended September 30, 2015 and the year ended December 31, 2014 (in thousands): September 30, December 31, 2015 2014 Beginning fair value of commodity derivatives $ $ Net gains on crude oil derivatives Net gains 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/(Loss) For the Three Months Ended September 30, For the Nine Months Ended September 30, Derivative Type in Income 2015 2014 2015 2014 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 four counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of September 30, 2015 and December 31, 2014, 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 95% , 90% , 85% , 85% and 80% of estimated 2015, 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 September 30, 2015, the fair value of the hedges assumed resulted in a $10.4 million asset in our condensed consolidated balance sheet.

Oil And Natural Gas Properties

Oil And Natural Gas Properties	9 Months Ended
	Sep. 30, 2015
Oil And Natural Gas Properties [Abstract]
Oil And Natural Gas Properties	6. OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties consisted of the following (in thousands): September 30, December 31, 2015 2014 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 $ $ Impairment of Oil and Natural Gas Properties and Other Non-Current Assets The Partnership evaluates the impairment of its proved oil and natural gas properties on a field-by-field basis whenever events or changes in circumstances indicate that the carrying value may not be recoverable. The carrying values of proved properties are reduced to fair value when the expected undiscounted future cash flows of proved and risk-adjusted probable and possible reserves are less than net book value. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) 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. For the three and nine months ended September 30, 2015, we recorded non-cash charges of $0.9 million and $84.7 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. For the nine months ended September 30, 2014, we recorded non-cash impairment charges of $0.2 million to impair the value of our oil and natural gas fields in Texas and Louisiana, with an immaterial amount being recorded during the three months ended September 30, 2014 . The carrying values of the impaired proved properties were reduced to fair value, estimated using inputs characteristic of a Level 3 fair value measurement. 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. We recorded no exploration and dry hole costs for the nine months ended September 30, 2015 and 2014.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2015
Long-Term Debt [Abstract]
Long-Term Debt	7. LONG-TERM DEBT Credit Agreement On March 31, 2015, the Partnership, as borrower, entered into a Third Amended and Restated Credit Agreement with Royal Bank of Canada, as administrative agent and collateral agent and the lenders party thereto, providing for a reserve-based credit facility with a borrowing base of $110 million, a maximum commitment of $500 million and a maturity date of March 31, 2020 (the “Credit Agreement”). The Partnership used $106.0 million in borrowings under the Credit Agreement on March 31, 2015 to finance the Eagle Ford acquisition, in part, and to repay $42.5 million due under the Second Amended and Restated Credit Agreement, with Societe Generale as administrative and collateral agent and a syndicate of five lenders, which had a maximum commitment of $350 million and a borrowing base of $70.0 million immediately prior to its retirement. Borrowings under the Credit Agreement are secured by various mortgages of oil and natural gas properties that the Partnership and certain of its subsidiaries own as well as various security and pledge agreements among the Partnership and certain of its subsidiaries and the administrative agent. The amount available for borrowing at any one time under the Credit Agreement is limited to the borrowing base for the Partnership’s oil and natural gas properties. Borrowings under the Credit Agreement are available for acquisition, exploration, operation, maintenance and development of oil and natural gas properties, payment of expenses incurred in connection with the Credit Agreement, working capital and general business purposes. The Credit Agreement has a sub-limit of $15 million which may be used for the issuance of letters of credit. The borrowing base as of September 30, 2015 was $110 million, of which we had $106 million outstanding. The borrowing base 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. 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. At the Partnership’s election, interest for borrowings under the Credit Agreement are determined by reference to (i) the London interbank rate, or 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 Agreement contains various covenants that limit, among other things, the Partnership’s ability and certain of its subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of the Partnership’s assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions. Furthermore, the Credit Agreement contains financial covenants that require the Partnership to satisfy certain specified financial ratios, including (i) current assets to current liabilities of at least 1.0 to 1.0 at all times and (ii) total net debt to consolidated Adjusted EBITDA for the last twelve months of not greater than 4.5 to 1.0 as of the last day of any fiscal quarter. The Credit Agreement also includes customary events of default, including events of default related 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) the Partnership’s existing general partner (the “General Partner”) ceases to be the sole general partner of the Partnership or (ii) certain specified persons shall cease to own more than 50% of the equity interests of the General Partner or shall cease to control, directly or indirectly, such General Partner. If an event of default occurs, the lenders may accelerate the maturity of the Credit Agreement and exercise other rights and remedies. The Credit Agreement limits the Partnership’s ability to pay distributions to unitholders. The Partnership has the ability to pay distributions to unitholders from available cash, including cash from borrowings under the Credit Agreement, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the Credit Agreement exceed 90% of the borrowing base determined with respect to the Partnership’s oil and natural gas properties, after giving effect to the proposed distribution. The Partnership’s available cash is reduced by any cash reserves established by the board of directors of the General Partner for the proper conduct of the Partnership’s business and the payment of fees and expenses. The Credit Agreement permits us to hedge our projected monthly production from oil and natural gas properties, provided that (a) for the immediately ensuing twenty four-month period, the volumes of production hedged in any month may not exceed our projected monthly production from proved developed and producing reserves (or 90% of our projected monthly production from proved reserves, if greater); (b) for the immediately following twenty-four month period, volumes of production hedged in any month may not exceed 90% of our projected monthly production from proved developed and producing reserves (or 85% of our projected monthly production from proved reserves, if greater); (c) for the immediately following twelve month period, volumes of production hedged in any month may not exceed 85% our projected monthly production from proved developed and producing reserves (or 80% of our projected monthly production from proved reserves, if greater); and (d) no hedges may have a tenor beyond five years. The Credit Agreement also permits us to hedge the interest rate on up to 75% of the then-outstanding principal amounts of our indebtedness for borrowed money. On October 14, 2015, in conjunction with the closing of the Western Catarina Midstream acquisition, the Partnership entered into the Joinder, Assignment and Second Amendment to the Credit Agreement with a syndicate of nine lenders (the “Amended Credit Agreemen t”). Pursuant to the amendment , the borrowing base under the Credit Facility increased from $110 million to $200 million, excluding the value of the Partnership’s Oklahoma and Kansas assets. Debt outstanding as of the date of the amendments was unchanged at $106 million . As a result of the amendment , which resulted in lower utilization of the borrowing base, the interest rate paid by the Partnership on the debt outstanding decreased by 0.50% . The borrowing base under the Amended Credit Agreement is re-determined semi-annually in the second and fourth quarters of the year with respect to our oil and gas properties and quarterly with respect to our midstream properties based on, among other things, reserve reports as prepared by petroleum engineers, prevailing oil and natural gas prices, and our operating results. The borrowing base may be re-determined at our request more frequently and by the lenders, at any time, in their sole discretion. The next regularly scheduled borrowing base redetermination is expected to occur in the second quarter 2016. The Amended Credit Agreement contains various covenants that limit, among other things, the Partnership’s ability and certain of its subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of the Partnership’s assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions. In addition, the Partnership is required to maintain the following financial covenants: (i) current assets to current liabilities of at least 1.0 to 1.0 at all times; (ii) 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 the Partnership’s midstream operations equals or exceeds one-third of total Adjusted EBITDA or 4.0 to 1.0 if the Adjusted EBITDA of the Partnership’s midstream operations is less than one-third of total Adjusted EBITDA; and (iii) minimum interest coverage ratio of at least 2.5 to 1.0 if the Adjusted EBITDA of the Partnership’s midstream operations is greater than one-third of the Partnership’s total Adjusted EBITDA. The Partnership has the ability to pay distributions to unitholders from available cash, including cash from borrowings under the Amended Credit Agreement, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the Amended Credit Agreement exceed 90% of the borrowing base attributable to the Partnership’s oil and gas properties, after giving effect to the proposed distribution. The Partnership’s available cash is reduced by any cash reserves established by the board of directors of the General Partner for the proper conduct of the Partnership’s business and the payment of fees and expenses. We monitor compliance with the covenants of the Credit Agreement on an ongoing basis. As of September 30, 2015, the Partnership's ratio of total net debt to Adjusted EBITDA, calculated in accordance with the terms of the Credit Agreement in effect as of September 30, 2015, exceeded 4.5 to 1.0. However, as a result of the Amended Credit Agreement, we are not required to provide a compliance certificate for the quarter ended September 30, 2015 as part of the normal quarterly compliance materials submitted to our lenders. As a result, the Partnership was deemed to be in compliance with its covenants as of September 30, 2015 and currently forecasts that its ratio of total net debt to Adjusted EBITDA will not exceed 4.5 to 1.0 for the next twelve months. Debt Issuance Costs As of September 30, 2015, our unamortized debt issuance costs were $1.6 million. These costs are amortized to interest expense in our consolidated statement of operations over the life of our Credit Agreement. At December 31, 2014, our unamortized debt issuance costs were $0.7 million.

Asset Retirement Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	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 changes in the ARO for the nine months ended September 30, 2015 and the year ended December 31, 2014 were as follows (in thousands): September 30, December 31, 2015 2014 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 September 30, 2015 and December 31, 2014, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs.

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	9. COMMITMENTS AND CONTINGENCIES We did not have any material commitments and contingencies as of September 30, 2015.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	10. RELATED PARTY TRANSACTIONS Unit Ownership As of September 30, 2015, a subsidiary of SN owned 105,263 common units , or 3.3% of our common units. As a result of the Western Catarina Midstream acquisition in October 2015, we repurchased all of the common units previously held by a subsidiary of SN. Sanchez-Related Agreements The Partnership and the Manager are parties to the Services Agreement pursuant to which the 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. Compensation for services provided under the Services Agreement consists 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) a $1,000,000 administrative fee, which was paid during 2014, (iii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iv) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, will be paid in cash unless the 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 the Manager and the Company provide notice to terminate the agreement. During the nine months ended September 30, 2015, we paid $5.3 million to the Manager under the Services Agreement. Additionally, as of September 30, 2015 and December 31, 2014, the Partnership had a net receivable from related parties of $0.7 million and $1.0 million, respectively, which are included in “Accounts receivable – related entities” in the condensed consolidated balance sheets. The net receivables as of September 30, 2015 and December 31, 2014 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 May 8, 2014, the Company and SOG entered into a Contract Operating Agreement, the Company, the Manager and SOG entered into a Transition Agreement, and the Company, SOG and certain subsidiaries of the Company entered into a Geophysical Seismic Data Use License Agreement (the “License Agreement”). For further discussion of these agreements, refer to our Annual Report on Form 10-K for the year ended December 31, 2014. On March 31, 2015, the Partnership and SN entered into a Purchase and Sale Agreement for the acquisition of the Eagle Ford properties for a purchase price of $85 million. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.”

Unit-Based Compensation

Unit-Based Compensation	9 Months Ended
	Sep. 30, 2015
Unit-Based Compensation [Abstract]
Unit-Based Compensation	11. 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 the 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”). Restricted unit activity under the Omnibus Plan, the Previous LTIP, and the LTIP during the period, after adjusting for the reverse split, is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2014 $ Granted Vested Returned/Cancelled Outstanding at September 30, 2015 $ During the nine months ended September 30, 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 d irector s of the Partnership’s general partner that vested immediately on the date of the grant. The unit based compensation expense for the award s w ere based on their grant date fair value s. 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. The remaining unvested units as of September 30, 2015 belong to one employee of a subsidiary of the Partnership and are due upon request. As such, we have accelerated the recognition of the expense associated with these awards into the nine months ended September 30, 2015.

Distributions To Unitholders

Distributions To Unitholders	9 Months Ended
	Sep. 30, 2015
Distributions To Unitholders [Abstract]
Distributions To Unitholders	12. DISTRIBUTIONS TO UNITHOLDERS Beginning in June 2009, we suspended our quarterly distributions to unitholders. For each of the quarterly periods since June 2009, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board for the proper conduct of our business) from which to pay distributions.

Members' Equity_Partners' Capit

Members' Equity/Partners' Capital	9 Months Ended
	Sep. 30, 2015
Members' Equity/Partners' Capital [Abstract]
Members' Equity/Partners' Capital	13. MEMBERS’ EQUITY/PARTNERS’ CAPITAL Outstanding Units As of September 30, 2015, we had 11,130,855 Class A Preferred Units outstanding and 3,149,693 common units outstanding, which included 25,641 unve sted restricted common units issued under the LTIP. Conversion The Company’s board of managers approved a Plan of Conversion (the “Conversion”) providing for the Conversion of the Company from a limited liability company formed under the laws of the State of Delaware into Sanchez LP, a limited partnership formed under the laws of the State of Delaware. This plan was approved by the vote of the unitholders of the Company on March 6, 2015. After the Conversion, all of the rights, privileges and obligations of the Company prior to the Conversion were transferred and are now held by the Partnership. The Conversion converted each outstanding common unit of the Company into one common unit of the Partnership. The outstanding Class A units of the Company were converted into common units of the Partnership in a number equal to 2% of the Partnership’s common units outstanding immediately after the Conversion (after taking into account the conversion of such Class A units), and the outstanding Class Z unit of the Company was cancelled. In addition, a non-economic general partner interest in the Partnership was issued to our general partner, and the incentive distribution rights of the Partnership were issued to the Manager. Common Unit Issuances 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 3,149,5 51 , not inclusive of shares required by DTCC due to the rounding up of fractional shares at the beneficial level, and the per unit opening trading price on the NYSE MKT. Preferred Unit Issuance Class A Preferred Unit Offerings: On March 31, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with the purchasers named on Schedule A thereto (collectively, the “Purchasers”), pursuant to which the Partnership sold, and the 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 (the “Private Placement”) 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 from this transaction, together with common units issued to SN, borrowings under the Credit Agreement, and available cash on hand, to pay the consideration in the Eagle Ford acquisition. Additionally, on April 15, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement (the “April 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 proceeds to the Partnership of $375,000 . The Partnership used the proceeds for general working capital purposes. Commencing with the three months ended June 30, 2015 and through the date on which the Class A Preferred Units are converted into common units, the holders of the Class A Preferred Units shall be entitled to receive distributions. For the three months ended June 30, 2015, through and including the three months ending June 30, 2016, the distributions will be paid in kind with additional Class A Preferred Units; thereafter, distributions will be paid in-kind or in cash at the discretion of the board of directors of our general partner. For the first year after the issuance date, the distribution rate will be 10% per annum, or 2.5% per quarter; for the second year after the issuance date, the distribution rate will be 11.5% per annum, or 2.875% per quarter; and thereafter, the distribution rate will be 12.5% per annum, or 3.125% per quarter. Distributions will be made on or about the last day of each of February, May, August and November following the end of each quarter commencing with the three months ended June 30, 2015. On August 10, 2015, the board of directors of our general partner declared a distribution to holders of Class A Preferred Units as of August 14, 2015 to be paid in kind for the three months ended June 30, 2015. This distribution to the holders was made on August 31, 2015. 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 Three Months Ended March 6 - September 30 January 1 - March 6 September 30, September 30, 2015 2015 2015 2014 Class A units - Basic — — Class B Common units - Basic — — Common units - Basic — — Weighted Average basic units prior to reverse split Adjustment for reverse split Weighted Average basic units after reverse split Class A units - Diluted — — Class B Common units - Diluted — — Common units - Diluted — — Weighted Average diluted units prior to reverse split Adjustment for reverse split Weighted Average diluted units after reverse split At September 30, 2015, we had 25,641 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 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 prior to reverse split $ $ Basic and diluted loss per unit after reverse split $ $ The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through September 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 - September 30 $ $ Basic and diluted loss per unit prior to reverse split $ Basic and diluted loss per unit after reverse split $ Net loss per unit increased significantly for the period from March 6, 2015 through September 30, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included non-cash impairment charges of $84.7 million. There was no impairment charge recorded for the period from January 1, 2015 through March 5, 2015. The following table presents our basic and diluted income per unit for the three months ended September 30, 2014 (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net income to be allocated $ $ $ Basic and diluted income per unit prior to reverse split $ $ Basic and diluted income per unit after reverse split $ $ The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2014 (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net loss to be allocated $ $ $ Basic and diluted loss per unit prior to reverse split $ $ Basic and diluted loss per unit after reverse split $ $

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	14. SUBSEQUENT EVENTS On October 14, 2015, we completed the Western Catarina Midstream acquisition for a purchase price of $345.8 million, subject to normal and customary closing adjustments. The purchase price was funded at closing with net proceeds from the sale of Class B Preferred Units to Stonepeak, a private equity firm that focuses on the infrastructure space, and available cash. In connection with the issuance of the Class B Preferred Units, Stonepeak has received two seats on the board of directors of SPP’s general partner and has appointed Luke Taylor and Jack Howell, each an employee of Stonepeak, to fill those seats. Additionally, as a result of the Western Catarina Midstream acquisition, we repurchased all of the common units previously held by a subsidiary of SN. On October 14, 2015, in conjunction with the closing of the Western Catarina Midstream acquisition, the Partnership entered into the Amended Credit Agreement . Pursuant to the amendment, the borrowing base under the Credit Facility increased from $110 million to $200 million, excluding the value of the Partnership’s Oklahoma and Kansas assets. Debt outstanding as of the date of the amendments was unchanged at $106 million . As a result of the amendment , which resulted in lower utilization of the borrowing base, the interest rate paid by the Partnership on the debt outstanding decreased by 0.50% . See further discussion in Note 7, “Long-Term Debt.” On November 10, 2015, the board of directors of our general partner declared a distribution to holders of Class A Preferred Units as of November 16, 2015 to be paid in kind and distributed to the holders on November 30, 2015. On November 10, 2015, the board of directors of our general partner declared a distribution of $0.40 per unit to holders of common units as of November 16, 2015 to be paid on November 30, 2015. On November 10, 2015, the board of directors of the Partnership’s general partner approved a $10 million common unit repurchase plan (the “Unit Repurchase Plan”). The repurchases will be funded from cash on hand or available borrowings. The Unit Repurchase Plan may be suspended or discontinued at any time without prior notice.

Organization And Basis Of Pre23

Organization And Basis Of Presentation (Policies)	9 Months Ended
	Sep. 30, 2015
Organization And Basis Of Presentation [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 operate our oil and natural gas properties as one business segment: the exploration, development and production of oil and natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties. 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, 2014, which was filed with the SEC on March 5, 2015.
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.
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 and an immaterial effect on total assets and total liabilities.
Recent Pronouncements And Accounting Changes	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 April 2015, FASB issued Accounting Standards Update (“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. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. In February 2015, the FASB issued an 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. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, but we do not expect the impact to be material. 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. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.

Summary Of Significant Accoun24

Summary Of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Summary Of Significant Accounting Policies [Abstract]
Cash	Cash 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 at September 30, 2015 and December 31, 2014.
Restricted Cash	Restricted Cash Restricted cash, as of September 30, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of September 30, 2015 is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved.
Accounts Receivable, Net	Accounts Receivable, Net Our accounts receivable are primarily from purchasers of oil and natural gas 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. At September 30, 2015 and December 31, 2014, we had an allowance for doubtful accounts receivable of $0.4 million and $0.2 million, respectively.

Acquisitions And Divestitures (

Acquisitions And Divestitures (Tables)	9 Months Ended
	Sep. 30, 2015
Acquisitions And Divestitures [Abstract]
Estimated Values Of Assets Acquired 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 Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Revenues $ $ $ $ Net income (loss) attributable to common unitholders $ $ $ $ Net income (loss) per unit prior to conversion Class A units - Basic and diluted (1) $ — $ $ $ Class B units - Basic (1) $ — $ $ $ Class B units - Diluted (1) $ — $ $ $ Net income (loss) per unit after conversion Common units - Basic (1) $ $ — $ $ — Common units - Diluted (1) $ $ — $ $ — (1) Amounts adjusted for 1 -for-10 reverse split completed August 3, 2015. See Note 13.
Post-Acquisition Operating Results	Three Nine Months Ended Months Ended September 30, 2015 September 30, 2015 Revenues $ $ Excess of revenues over direct operating expenses $ $

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
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 September 30, 2015 (in thousands): Fair Value Measurements at September 30, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral September 30, 2015 Derivative assets $ — $ $ — $ — $ 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, 2014 (in thousands): Fair Value Measurements at December 31, 2014 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2014 Derivative assets $ — $ $ — $ $ Derivative liabilities — — — Total net assets $ — $ $ — $ — $

Derivative And Financial Inst27

Derivative And Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative And Financial Instruments [Abstract]
Summary Of Hedges In Place	Fixed Price Basis Swaps–West Texas Intermediate (WTI) For the Quarter Ended (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 2015 $ $ 2016 $ $ $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ Fixed Price Swaps—NYMEX (Henry Hub) For the Quarter Ended (in MMBtu) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2015 $ $ 2016 $ $ $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $
Schedule Of Change In Commodity Derivatives Fair Value	September 30, December 31, 2015 2014 Beginning fair value of commodity derivatives $ $ Net gains on crude oil derivatives Net gains 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 Condensed Consolidated Statements Of Operations	Amount of Gain/(Loss) in Income Location of Gain/(Loss) For the Three Months Ended September 30, For the Nine Months Ended September 30, Derivative Type in Income 2015 2014 2015 2014 Commodity – Mark-to-Market Oil sales $ $ $ $ Commodity – Mark-to-Market Natural gas sales $ $ $ $

Oil And Natural Gas Properties

Oil And Natural Gas Properties (Tables)	9 Months Ended
	Sep. 30, 2015
Oil And Natural Gas Properties [Abstract]
Oil and Natural Gas Properties	September 30, December 31, 2015 2014 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 $ $

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligation [Abstract]
Reconciliation of Asset Retirement Obligation	September 30, December 31, 2015 2014 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 $ $

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2015
Unit-Based Compensation [Abstract]
Schedule Of Units Granted	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2014 $ Granted Vested Returned/Cancelled Outstanding at September 30, 2015 $

Members' Equity_Partners' Cap31

Members' Equity/Partners' Capital (Tables)	9 Months Ended
	Sep. 30, 2015
Members' Equity/Partners' Capital [Abstract]
Schedule Of Weighted Average Units Outstanding	Three Months Ended Three Months Ended March 6 - September 30 January 1 - March 6 September 30, September 30, 2015 2015 2015 2014 Class A units - Basic — — Class B Common units - Basic — — Common units - Basic — — Weighted Average basic units prior to reverse split Adjustment for reverse split Weighted Average basic units after reverse split Class A units - Diluted — — Class B Common units - Diluted — — Common units - Diluted — — Weighted Average diluted units prior to reverse split Adjustment for reverse split Weighted Average diluted units after reverse split
Earnings Per Common Unit Amounts	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 prior to reverse split $ $ Basic and diluted loss per unit after reverse split $ $ The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through September 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 - September 30 $ $ Basic and diluted loss per unit prior to reverse split $ Basic and diluted loss per unit after reverse split $ Net loss per unit increased significantly for the period from March 6, 2015 through September 30, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included non-cash impairment charges of $84.7 million. There was no impairment charge recorded for the period from January 1, 2015 through March 5, 2015. The following table presents our basic and diluted income per unit for the three months ended September 30, 2014 (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net income to be allocated $ $ $ Basic and diluted income per unit prior to reverse split $ $ Basic and diluted income per unit after reverse split $ $ The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2014 (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net loss to be allocated $ $ $ Basic and diluted loss per unit prior to reverse split $ $ Basic and diluted loss per unit after reverse split $ $

Summary Of Significant Accoun32

Summary Of Significant Accounting Policies (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Restricted cash	$ 600	$ 1,748
Allowance for doubtful accounts	400	200
Checks-In-Transit [Member]
Cash	$ 0	$ 0

Acquisitions And Divestitures33

Acquisitions And Divestitures (Details) - USD ($)	Oct. 14, 2015	Apr. 15, 2015	Mar. 31, 2015	Sep. 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
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
Subsequent Event [Member] | Western Catarina Midstream [Member]
Business Acquisition [Line Items]
Cash payment for acquisition	$ 345,800,000
Repurchase of units (in units)	105,263

Acquisitions And Divestitures34

Acquisitions And Divestitures (Value Net Assets Acquired) (Details) - Eagle Ford [Member] $ in Thousands	Mar. 31, 2015USD ($)
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

Acquisitions And Divestitures35

Acquisitions And Divestitures (Pro Forma) (Details) $ / shares in Units, $ in Thousands	Aug. 03, 2015	Sep. 30, 2015USD ($)$ / shares	Sep. 30, 2014USD ($)$ / sharesshares	Sep. 30, 2015USD ($)$ / sharesshares	Sep. 30, 2014USD ($)$ / sharesshares
Business Acquisition [Line Items]
Reverse stock split ratio	0.1
Eagle Ford [Member]
Business Acquisition [Line Items]
Revenue		$ 36,219	$ 43,534	$ 77,341	$ 115,449
Net income (loss) attributable to common unitholders		1,109	$ 5,522	(112,483)	$ 633
Revenue, actual		2,390		5,718
Excess of revenues over direct operating expenses, actual		$ 1,439		$ 3,742
Class A Unit [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Weighted average units outstanding - Basic and diluted | shares			6.40	(23.83)	7.13
Class B Unit [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic (in dollars per unit) | $ / shares			$ 5.43	$ (18.95)	$ 10.56
Net income (loss) - pro forma diluted (in dollars per unit) | $ / shares			$ 0.80	(18.95)	$ 1.88
Common Units [Member]
Business Acquisition [Line Items]
Reverse stock split ratio	0.1
Common Units [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic (in dollars per unit) | $ / shares		$ 3.38		(8.74)
Net income (loss) - pro forma diluted (in dollars per unit) | $ / shares		$ 0.60		$ (8.74)

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Recurring - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative asset, netting cash and collateral		$ (90)
Fair value of derivative instruments	$ 27,908	22,829
Derivative liability, netting cash and collateral		90
Total Net Assets and Liabilities	27,908	22,829
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	27,908	22,919
Derivative liabilities		(90)
Total Net Assets and Liabilities	$ 27,908	$ 22,829

Derivative And Financial Inst37

Derivative And Financial Instruments (Hedges In Place) (Details)	9 Months Ended
	Sep. 30, 2015MMBTU$ / MMBTUbbl
Derivative [Line Items]
Average Price	65.65
West Texas Intermediate 2015 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	109,582
Average Price	75.64
West Texas Intermediate 2015 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	109,582
Average Price	75.64
West Texas Intermediate 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	121,005
Average Price	73.53
West Texas Intermediate 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	113,226
Average Price	73.77
West Texas Intermediate 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	106,483
Average Price	73.95
West Texas Intermediate 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	100,525
Average Price	74.10
West Texas Intermediate 2016 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	441,239
Average Price	73.82
West Texas Intermediate 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	57,953
Average Price	64.80
West Texas Intermediate 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	54,554
Average Price	64.80
West Texas Intermediate 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	51,570
Average Price	64.80
West Texas Intermediate 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	48,926
Average Price	64.80
West Texas Intermediate 2017 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	213,003
Average Price	64.80
West Texas Intermediate 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	56,798
Average Price	65.40
West Texas Intermediate 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	54,197
Average Price	65.40
West Texas Intermediate 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	51,851
Average Price	65.40
West Texas Intermediate 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	49,709
Average Price	65.40
West Texas Intermediate 2018 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	212,555
Average Price	65.40
West Texas Intermediate 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	52,760
Average Price	65.65
West Texas Intermediate 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	50,784
Average Price	65.65
West Texas Intermediate 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	48,960
West Texas Intermediate 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	47,264
Average Price	65.65
West Texas Intermediate 2019 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	199,768
Average Price	65.65
West Texas Intermediate [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	1,176,147
NYMEX 2015 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,118,334
Average Price	4.17
NYMEX 2015 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,118,334
Average Price	4.17
NYMEX 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,098,689
Average Price	4.13
NYMEX 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,048,146
Average Price	4.14
NYMEX 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	998,394
Average Price	4.14
NYMEX 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	963,327
Average Price	4.14
NYMEX 2016 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	4,108,556
Average Price	4.14
NYMEX 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	80,563
Average Price	3.52
NYMEX 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	75,829
Average Price	3.52
NYMEX 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	71,672
Average Price	3.52
NYMEX 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	67,984
Average Price	3.52
NYMEX 2017 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	296,048
Average Price	3.52
NYMEX 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	79,042
Average Price	3.58
NYMEX 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	75,404
Average Price	3.58
NYMEX 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	72,115
Average Price	3.58
NYMEX 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	69,122
Average Price	3.58
NYMEX 2018 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	295,683
Average Price	3.58
NYMEX 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	73,432
Average Price	3.62
NYMEX 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	70,648
Average Price	3.62
NYMEX 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	68,088
Average Price	3.62
NYMEX 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	65,720
Average Price	3.62
NYMEX 2019 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	277,888
Average Price	3.62
NYMEX [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	6,096,509

Derivative And Financial Inst38

Derivative And Financial Instruments (Change In Fair Value) (Details) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)item	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ 17,322	$ 7,671	$ 16,258	$ (1,134)
Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives			22,829	10,601	$ 10,601
Ending fair value of commodity derivatives	27,908		$ 27,908		22,829
Number of counterparties | item			4
Oil [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives			$ 15,321		13,983
Net settlements on derivative contracts			(9,532)		69
Oil [Member] | Oil And Liquids Sales [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	14,970	4,904	12,058	(98)
Natural Gas [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives			4,343		5,871
Net settlements on derivative contracts			(5,053)		$ (7,695)
Natural Gas [Member] | Natural Gas Sales [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ 2,352	$ 2,767	$ 4,200	$ (1,036)

Derivative And Financial Inst39

Derivative And Financial Instruments (EagleFord) (Details) - Eagle Ford [Member] $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Derivative [Line Items]
Oil and natural gas production, 2015	95.00%
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	$ 10.4

Oil And Natural Gas Propertie40

Oil And Natural Gas Properties (Properties) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Oil And Natural Gas Properties [Abstract]
Proved property	$ 730,678	$ 649,432
Unproved property	1,587	1,560
Land	501	501
Total property costs	732,766	651,493
Materials and supplies	1,056	1,056
Total	733,822	652,549
Less: Accumulated depreciation, depletion, amortization and impairments	(610,279)	(517,239)
Oil and natural gas properties and equipment, net	$ 123,543	$ 135,310

Oil and Natural Gas Propertie41

Oil and Natural Gas Properties (DDA and Impairments) (Details) - USD ($) $ in Thousands	3 Months Ended			4 Months Ended	9 Months Ended
	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Oil And Natural Gas Properties [Abstract]
Asset impairments	$ 937	$ 84,700	$ 43	$ 0	$ 84,664	$ 237
Exploration costs					$ 0	$ 0

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	Oct. 13, 2015USD ($)item	Mar. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Line of Credit Facility [Line Items]
Amount of debt repaid			$ 42,500	$ 4,500
Unamortized debt issue costs			1,600		$ 700
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Borrowing base amount		$ 110,000	110,000
Maximum borrowing capacity		500,000
Amount borrowed under credit facility		106,000	$ 106,000
Projected monthly production from proved reserves, first 24 months			90.00%
Projected monthly production from proved developed and producing reserves			90.00%
Projected monthly production from proved reserves, following 24 month period			85.00%
Projected monthly production from proved developed and producing reserves, following 12 month period			85.00%
Projected monthly production from proved reserves following 12 month period			80.00%
Maximum term on hedge			5 years
Maximum hedge on interest rate			75.00%
Second Amended And Restated Credit Agreement [Member]
Line of Credit Facility [Line Items]
Borrowing base amount		70,000
Maximum borrowing capacity		350,000
Amount of debt repaid		$ 42,500
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity			$ 15,000
Minimum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base			0.375%
Consolidated current asset ratio			1
Ownership percentage by subsidiary			50.00%
Exceeding of reserve-based credit facility over borrowing base (as a percent)			90.00%
Minimum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Variable interest rate			1.75%
Minimum [Member] | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Variable interest rate			0.75%
Maximum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base			0.50%
Debt to Adjusted EBITDA ratio			4.5
Maximum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Variable interest rate			2.75%
Maximum [Member] | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Variable interest rate			1.75%
Subsequent Event [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Borrowing base amount	$ 200,000
Amount borrowed under credit facility	$ 106,000
Consolidated current asset ratio	1
Number of counterparties | item	9
Increase (decrease) interest rate (as a percent)	(0.50%)
Required interest coverage ratio	2.5
Maximum borrowings to allow distributions (as a percent)	90.00%
Subsequent Event [Member] | Credit Agreement [Member] | Scenario One [Member]
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5
Subsequent Event [Member] | Credit Agreement [Member] | Scenario Two [Member]
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Asset retirement obligation, beginning balance			$ 17,031	$ 9,513	$ 9,513
Liabilities added from acquisitions			877		80
Liabilities added from drilling					59
Sold			(59)
Revisions to cost estimates					6,780
Settlements			(38)		(5)
Accretion expense	$ 265	$ 151	782	$ 451	604
Asset retirement obligation, ending balance	$ 18,593		$ 18,593		$ 17,031

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	Mar. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Accounts receivable - related entities		$ 681,000	$ 959,000
SP Holdings [Member]
Related Party Transaction [Line Items]
Percent of value of properties held used to compute quarterly fee		0.375%
Administrative fee		$ 1,000,000
Maximum asset acquisition, disposition and financing fee		2.00%
Term of Services Agreement		10 years
Term of Services Agreement renewal		10 years
Administrative fee paid		$ 5,300,000
Eagle Ford [Member]
Related Party Transaction [Line Items]
Cash payment for acquisition	$ 83,400,000
Eagle Ford [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Cash payment for acquisition	$ 85,000,000
Common Units [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Units owned by third party		105,263
Units owned by third party, percentage of total shares		3.30%

Unit-Based Compensation (Activi

Unit-Based Compensation (Activity) (Details) - LTIP [Member]	9 Months Ended
	Sep. 30, 2015$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	25,641
Restricted Stock Units (RSUs) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	10,082
Number of Restricted Units, Granted	(137,257)
Number of Restricted Units, Vested	(87,872)
Number of Restricted Units, Returned/Cancelled	(33,826)
Number of Restricted Units, Outstanding	25,641
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ / shares	$ 31.10
Weighted Averaged Grant Date Fair Value Per Unit, Granted | $ / shares	17.07
Weighted Averaged Grant Date Fair Value Per Unit, Vested | $ / shares	18.68
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled | $ / shares	17.33
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ / shares	$ 16.50

Unit-Based Compensation (Expens

Unit-Based Compensation (Expense) (Details) - Restricted Stock Units (RSUs) [Member] - shares	1 Months Ended	9 Months Ended
	Mar. 31, 2015	Sep. 30, 2015
Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted		34,693
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
Prior To Stock Split [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] | 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

Distributions To Unitholders (D

Distributions To Unitholders (Details) $ in Thousands	Sep. 30, 2015USD ($)
Distributions To Unitholders [Abstract]
Available cash balance	$ 0

Members' Equity_Partners' Cap48

Members' Equity/Partners' Capital (Details)	Aug. 03, 2015shares	Apr. 15, 2015USD ($)$ / sharesshares	Mar. 31, 2015USD ($)$ / sharesshares	Mar. 06, 2015	Sep. 30, 2015USD ($)shares	Aug. 02, 2015$ / sharesshares	Dec. 31, 2014shares
Limited Partners' Capital Account [Line Items]
Reverse stock split ratio	0.1
Proceeds from common units sold | $					$ 52,000
Proceeds from preferred units sold | $					$ 17,375,000
LTIP [Member]
Limited Partners' Capital Account [Line Items]
Restricted unvested common units granted and outstanding					25,641
Class A Preferred [Member]
Limited Partners' Capital Account [Line Items]
Preferred units, outstanding					11,130,855		0
Units sold (in units)		234,375	10,625,000
Price per unit sold | $ / shares		$ 1.60	$ 1.60
Proceeds from preferred units sold | $		$ 375,000	$ 17,000,000
Distribution rate, first year					10.00%
Distribution rate, first year, quarterly					2.50%
Distribution rate, second year					11.50%
Distribution rate, second year, quarterly					2.875%
Distribution rate, third year					12.50%
Distribution rate, third year, quarterly					3.125%
Class A Unit [Member]
Limited Partners' Capital Account [Line Items]
Common units, outstanding					0
Common units, issued					0		48,451	[1]
Class B Unit [Member]
Limited Partners' Capital Account [Line Items]
Common units, outstanding					0
Common units, issued					0		2,879,258	[1]
Common Units [Member]
Limited Partners' Capital Account [Line Items]
Common units, outstanding	3,149,582				3,149,693	31,495,506
Percent of common units outstanding				2.00%
Reverse stock split ratio	0.1
Common units, issued	3,149,551					31,495,506	0
Closing market price | $ / shares						$ 1.55
[1]	(1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.

Members' Equity_Partners' Cap49

Members' Equity/Partners' Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Thousands		3 Months Ended			4 Months Ended	7 Months Ended	9 Months Ended
		Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Jun. 30, 2015	Sep. 30, 2015	Sep. 30, 2015	Sep. 30, 2014
Weighted average units outstanding, basic		3,124,004					3,103,608
Weighted average units outstanding, diluted	[1]	14,074,856					3,103,608
Assumed net loss		$ 7,350	$ (923)	$ 5,655		$ (92,578)	$ (93,501)	$ (2,295)
Asset impairments		$ 937	84,700	$ 43	$ 0		$ 84,664	$ 237
Class A Unit [Member]
Weighted average units outstanding, basic	[1]			48,451			48,451	85,720
Weighted average units outstanding, diluted	[1]			48,451			48,451	85,720
Assumed net loss			$ (18)	$ 113				$ (46)
Net loss per unit - Basic and diluted			$ (0.38)	$ 2.33				$ (0.54)
Class B Unit [Member]
Weighted average units outstanding, basic	[1]			2,855,257			2,879,163	2,835,859
Weighted average units outstanding, diluted	[1]			2,866,088			2,879,163	2,835,859
Assumed net loss			$ (905)	$ 5,542				$ (2,249)
Net loss per unit - Basic and diluted			$ (0.31)	$ 1.93				$ (0.79)
Common Units [Member]
Weighted average units outstanding, basic		3,124,004	2,927,613	2,903,707		3,103,608
Adjustment for reverse split		(28,116,034)	(26,348,518)	(26,133,366)		(27,932,467)
Weighted average units outstanding, diluted		14,074,856	2,927,613	2,914,537		3,103,608
Adjustment for reverse split - diluted		(126,673,701)	(26,348,518)	(26,230,846)		(27,932,467)
Assumed net loss						$ (92,578)
Net loss per unit - Basic and diluted						$ (29.83)
Prior To Stock Split [Member] | Class A Unit [Member]
Weighted average units outstanding, basic			484,505	484,505
Weighted average units outstanding, diluted			484,505	484,505
Net loss per unit - Basic and diluted			$ (0.04)	$ 0.23				(0.05)
Prior To Stock Split [Member] | Class B Unit [Member]
Weighted average units outstanding, basic			28,791,626	28,552,568
Weighted average units outstanding, diluted			28,791,626	28,660,878
Net loss per unit - Basic and diluted			$ (0.03)	$ 0.19				$ (0.08)
Prior To Stock Split [Member] | Common Units [Member]
Weighted average units outstanding, basic		31,240,038	29,276,131	29,037,073		31,036,075
Weighted average units outstanding, diluted		140,748,557	29,276,131	29,145,383		31,036,075
Net loss per unit - Basic and diluted						$ (2.98)
[1]	(1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Millions	Oct. 14, 2015USD ($)item	Oct. 13, 2015USD ($)	Nov. 10, 2015USD ($)$ / shares	Sep. 30, 2015USD ($)	Mar. 31, 2015USD ($)
Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions declared (in dollars per unit) | $ / shares			$ 0.40
Western Catarina Midstream [Member]
Subsequent Event [Line Items]
Maximum borrowing capacity				$ 110
Western Catarina Midstream [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Cash payment for acquisition	$ 345.8
Number of board of director seats | item	2
Maximum borrowing capacity	$ 200
Amount borrowed under credit facility	$ 106
Increase (decrease) interest rate (as a percent)	0.50%
Credit Agreement [Member]
Subsequent Event [Line Items]
Maximum borrowing capacity					$ 500
Amount borrowed under credit facility				$ 106	$ 106
Credit Agreement [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Amount borrowed under credit facility		$ 106
Increase (decrease) interest rate (as a percent)		(0.50%)
Common Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Authorized unit repurchase program			$ 10

Uncategorized Items - spp-20150

Label	Element	Value
Stock Issued During Period Value Stock Options Exercised	us-gaap_StockIssuedDuringPeriodValueStockOptionsExercised	$ 2,463
Units Tendered By Employees In Lieu Of Tax	spp_UnitsTenderedByEmployeesInLieuOfTax	597
Stock Issued During Period, Value, Acquisitions	us-gaap_StockIssuedDuringPeriodValueAcquisitions	2,000
Partners' Capital Account, Private Placement of Units	us-gaap_PartnersCapitalAccountPrivatePlacementOfUnits	16,550
Stock Issued During Period, Value, New Issues	us-gaap_StockIssuedDuringPeriodValueNewIssues	$ 157
Class B Unit [Member]
Stock Issued During Period, Shares, Share-based Compensation, Forfeited	us-gaap_StockIssuedDuringPeriodSharesShareBasedCompensationForfeited	2,877,701	[1]
Partners' Capital Account, Exchanges and Conversions	us-gaap_PartnersCapitalAccountExchangesAndConversions	$ (103,967)
Class Preferred [Member]
Benefit Conversion Feature	spp_BenefitConversionFeature	$ (1,693)
Preferred Stock Dividends, Shares	us-gaap_PreferredStockDividendsShares	271,480
Dividends, Preferred Stock, Paid-in-kind	us-gaap_DividendsPreferredStockPaidinkind	$ (969)
Partners' Capital Account, Private Placement of Units	us-gaap_PartnersCapitalAccountPrivatePlacementOfUnits	$ 16,550
Partners' Capital Account, Units, Sold in Private Placement	us-gaap_PartnersCapitalAccountUnitsSoldInPrivatePlacement	10,859,375
Class Unit [Member]
Partners' Capital Account, Units, Converted	us-gaap_PartnersCapitalAccountUnitsConverted	(48,451)	[1]
Partners' Capital Account, Exchanges and Conversions	us-gaap_PartnersCapitalAccountExchangesAndConversions	$ (1,912)
Lp Common Units [Member]
Stock Issued During Period Value Stock Options Exercised	us-gaap_StockIssuedDuringPeriodValueStockOptionsExercised	2,463
Units Tendered By Employees In Lieu Of Tax	spp_UnitsTenderedByEmployeesInLieuOfTax	597
Benefit Conversion Feature	spp_BenefitConversionFeature	1,693
Stock Issued During Period, Value, Acquisitions	us-gaap_StockIssuedDuringPeriodValueAcquisitions	2,000
Dividends, Preferred Stock, Paid-in-kind	us-gaap_DividendsPreferredStockPaidinkind	$ 969
Stock Issued During Period, Shares, Acquisitions	us-gaap_StockIssuedDuringPeriodSharesAcquisitions	105,263	[1]
Stock Issued During Period Shares Stock Options Exercised	us-gaap_StockIssuedDuringPeriodSharesStockOptionsExercised	137,257	[1]
Shares Paid For Tax Withholding For Share Based Compensation	us-gaap_SharesPaidForTaxWithholdingForShareBasedCompensation	32,269	[1]
Net income (loss)	us-gaap_NetIncomeLoss	$ (91,609)
Stock Issued During Period, Shares, New Issues	us-gaap_StockIssuedDuringPeriodSharesNewIssues	3,012	[1]
Stock Issued During Period, Value, New Issues	us-gaap_StockIssuedDuringPeriodValueNewIssues	$ 157
Lp Common Units [Member] | Scenario One [Member]
Partners' Capital Account, Units, Converted	us-gaap_PartnersCapitalAccountUnitsConverted	58,729	[1]
Partners' Capital Account, Exchanges and Conversions	us-gaap_PartnersCapitalAccountExchangesAndConversions	$ 1,912
Lp Common Units [Member] | Scenario Two [Member]
Partners' Capital Account, Units, Converted	us-gaap_PartnersCapitalAccountUnitsConverted	2,877,701	[1]
Partners' Capital Account, Exchanges and Conversions	us-gaap_PartnersCapitalAccountExchangesAndConversions	$ 103,967
[1]	(1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.