Evolve Transition Infrastructure (SNMP) 10-Q 14 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 13, 2015
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Trading Symbol	spp
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		3,149,551

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues
Natural gas sales		$ 3,642	$ 6,575	$ 10,216	$ 12,599
Oil and liquids sales		1,139	5,514	6,489	11,231
Total revenues		4,781	12,089	16,705	23,830
Operating expenses:
Lease operating expenses		5,358	5,182	10,258	10,302
Cost of sales		125	434	330	794
Production taxes		583	995	953	1,767
General and administrative		3,746	5,591	13,293	9,162
Gain on sale of assets		(54)	(16)	(113)	(23)
Depreciation, depletion and amortization		3,079	4,320	6,199	8,370
Asset impairments		862	45	83,727	194
Accretion expense		264	150	517	300
Total operating expenses		13,963	16,701	115,164	30,866
Other expenses (income)
Interest expense		1,122	533	1,768	1,058
Other expense (income)		37	(134)	100	(144)
Total other expenses		1,159	399	1,868	914
Total expenses		15,122	17,100	117,032	31,780
Net loss		(10,341)	(5,011)	(100,327)	(7,950)
Less:
Preferred unit paid-in-kind distributions		(524)		(524)
Net loss attributable to common unitholders		$ (10,865)	$ (5,011)	$ (100,851)	$ (7,950)
Earnings Per Share Basic And Diluted After Conversion [Abstract]
Common units - Basic and diluted	[1]	$ (3.49)		$ (32.37)
Earnings Per Share Basic And Diluted Other Disclosures, After Conversion [Abstract]
Common units - Basic and diluted	[1]	3,113,428		3,087,431
Common Class A [Member]
Net loss per unit prior to conversion
Net loss per unit - Basic and diluted	[1]		$ (2.07)	$ (0.38)	$ (1.52)
Weighted Average Units Outstanding
Weighted Average Units Outstanding - Basic and diluted	[1]		48,451	48,451	104,664
Common Class B [Member]
Net loss per unit prior to conversion
Net loss per unit - Basic and diluted	[1]		$ (1.73)	$ (0.31)	$ (2.76)
Weighted Average Units Outstanding
Weighted Average Units Outstanding - Basic and diluted	[1]		2,830,538	2,879,163	2,825,999
[1]	Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.

Condensed Consolidated Stateme3

Condensed Consolidated Statements Of Operations (Paranthetical) - Aug. 03, 2015	Total
Reverse stock split ratio	1-for-10
Subsequent Event [Member]
Number of common units received for every ten common units held	0.1

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 5,224	$ 4,238
Restricted cash	600	1,748
Accounts receivable	2,735	3,901
Accounts receivable - related entities	2,541	959
Prepaid expenses	1,375	1,783
Fair value of derivative instruments	11,434	14,671
Total current assets	23,909	27,300
Oil and natural gas properties and related equipment (successful efforts method)
Oil and natural gas properties, equipment and facilities	732,827	651,493
Material and supplies	1,056	1,056
Less accumulated depreciation, depletion, amortization, and impairments	(606,607)	(517,239)
Oil and natural gas properties and equipment, net	127,276	135,310
Other assets
Debt issuance costs	1,660	689
Fair value of derivative instruments	4,426	8,158
Other non-current assets	2,521	1,790
Total assets	159,792	173,247
Current liabilities
Accounts payable and accrued liabilities	7,522	5,759
Royalties payable	735	1,134
Fair value of derivative instruments	257
Total current liabilities	8,514	6,893
Other liabilities
Asset retirement obligation	18,395	17,031
Long-term debt	106,000	42,500
Total other liabilities	124,395	59,531
Total liabilities	$ 132,909	$ 66,424
Commitments and contingencies (See Note 9)
Members' equity / Partners' capital
Total members' equity/partners' capital	$ 26,883	$ 106,823
Total liabilities and members' equity/partners' capital	159,792	173,247
Common Class A [Member]
Members' equity / Partners' capital
General partners' capital account		1,930
Common Class B [Member]
Members' equity / Partners' capital
General partners' capital account		$ 104,893
Class A Preferred Units [Member]
Members' equity / Partners' capital
Class A preferred units	14,566
Common Units [Member]
Members' equity / Partners' capital
LP common units	$ 12,317

Condensed Consolidated Balance5

Condensed Consolidated Balance Sheets (Parenthetical)	Jun. 30, 2015shares		Dec. 31, 2014shares
Share units outstanding	3,145,060
Common Class A [Member]
Share units issued	0		48,451	[1]
Share units outstanding	0		48,451	[1]
Common Class B [Member]
Share units issued	0		2,879,258	[1]
Share units outstanding	0		2,879,258	[1]
Class A Preferred Units [Member]
Preferred units issued	10,859,375		0
Preferred units outstanding	10,859,375		0
Common Units [Member]
Common units, issued	3,145,060	[1]	0
Common units, outstanding	3,145,060	[1]	0
[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	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net loss	$ (100,327)	$ (7,950)
Adjustments to reconcile net loss to cash provided by operating activities
Depreciation, depletion and amortization	6,199	8,370
Asset impairments	83,727	194
Amortization of debt issuance costs	324	127
Accretion expense	517	300
Equity earnings in affiliate	48	(70)
Gain from disposition of property and equipment	(113)	(23)
Bad debt expense	122	112
Total mark-to-market losses on commodity derivative contracts	1,066	8,805
Cash mark-to-market settlements on commodity derivative contracts	8,950	2,107
Unit-based compensation programs	2,388	1,130
Changes in Operating Assets and Liabilities:
(Increase) decrease in accounts receivable	1,721	(3,489)
Increase in accounts receivable - related entities	(1,582)
Decrease in prepaid expenses	408	1,272
(Increase) decrease in other assets	(981)	2
Increase (decrease) in accounts payable/accrued liabilities	2,788	(4,957)
Increase (decrease) in royalties payable	(399)	96
Net cash provided by operating activities	4,856	6,026
Cash flows from investing activities:
Cash paid for acquisitions	(81,378)	(1,351)
Development of natural gas properties	(1,056)	(3,819)
Proceeds from sale of assets	344	58
Distributions from equity affiliate	15	140
Net cash used in investing activities	(82,075)	(4,972)
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)	(157)
Debt issuance costs	(1,294)	(136)
Net cash provided by (used in) financing activities	78,205	(1,511)
Net increase (decrease) in cash and cash equivalents	986	(457)
Cash and cash equivalents, beginning of period	4,238	4,894
Cash and cash equivalents, end of period	5,224	4,437
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	(149)	(542)
Accrual for cancellation of Class A units		818
Acquisitions of oil and natural gas properties in exchange for common units	2,000
Cash paid during the period for interest	(1,154)	(950)
Cash paid during the period for income taxes	$ (2)	$ (2)

Condensed Consolidated Stateme7

Condensed Consolidated Statements Of Changes In Members' Equity/Partners' Capital - USD ($) $ in Thousands		Common Class A [Member]Common Units [Member]		Common Class A [Member]		Common Class B [Member]Common Units [Member]		Common Class B [Member]	Class A Preferred Units [Member]	Common Units [Member]		Total
Beginning Balance (in shares) at Dec. 31, 2013				161,502	[1]			2,846,218
Beginning Balance at Dec. 31, 2013				$ 2,591				$ 96,314				$ 98,905
Units tendered by employees for tax withholding (in shares)								(16,018)
Units tendered by employees for tax withholding								$ (415)				(415)
Unit-based compensation programs (in shares)								49,058
Unit-based compensation programs								$ 1,298				1,298
Cancellation of units (in shares) (See Note 9)	[1]			(113,051)
Cancellation of units				$ (851)				(1,617)				(2,468)
Net income (loss)				$ 190				$ 9,313				9,503
Ending Balance (in shares) at Dec. 31, 2014				48,451	[1]			2,879,258
Ending Balance at Dec. 31, 2014				$ 1,930				$ 104,893				106,823
Units tendered by employees for tax withholding (in shares)								(1,557)
Units tendered by employees for tax withholding								$ (21)				(21)
Net income (loss)				$ (18)				$ (905)				(923)
Ending Balance (in shares) at Mar. 05, 2015				48,451	[1]			2,877,701
Ending Balance at Mar. 05, 2015				$ 1,912				$ 103,967				105,879
Beginning Balance (in shares) at Dec. 31, 2014				48,451	[1]			2,879,258
Beginning Balance at Dec. 31, 2014				$ 1,930				$ 104,893				106,823
Net income (loss)												(100,327)
Ending Balance (in shares) at Jun. 30, 2015									10,859,375	3,145,060	[1]
Ending Balance at Jun. 30, 2015									$ 14,566	$ 12,317		26,883
Beginning Balance (in shares) at Mar. 05, 2015				48,451	[1]			2,877,701
Beginning Balance at Mar. 05, 2015				$ 1,912				$ 103,967				105,879
Units tendered by employees for tax withholding (in shares)	[1]									(32,269)
Units tendered by employees for tax withholding										$ (597)		(597)
Unit-based compensation programs (in shares)	[1]									132,766
Unit-based compensation programs										$ 2,388		2,388
Private placement of Class A Preferred Units (in shares)									10,859,375
Private placement of Class A Preferred Units									$ 16,565			16,565
Beneficial conversion feature of Class A Preferred Units									(2,523)	$ 2,523
Units converted to LP Common Units upon limited partnerships (in shares)		58,729	[1]	(48,451)	[1]	2,877,701	[1]	(2,877,701)
Units converted to LP Common Units upon limited partnerships		$ 1,912		$ (1,912)		$ 103,967		$ (103,967)
Common units issued for acquisition of properties (in shares)	[1]									105,263
Common units issued for acquisition of properties										$ 2,000		2,000
Issuance of common units (in shares)	[1]									2,870
Issuance of common units										$ 52		52
Preferred unit paid-in-kind distributors									$ 524	(524)
Net income (loss)										$ (99,404)		(99,404)
Ending Balance (in shares) at Jun. 30, 2015									10,859,375	3,145,060	[1]
Ending Balance at Jun. 30, 2015									$ 14,566	$ 12,317		$ 26,883
[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 (Paranthetical) $ in Thousands	Jun. 30, 2015USD ($)
Class A Preferred Units [Member]
Offering costs	$ 810

Organization And Basis Of Prese

Organization And Basis Of Presentation	6 Months Ended
	Jun. 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 an oil and gas ex ploration and production limited partnership focused on the acquisition, development and production of oil and natural gas properties and other integrated assets . SPP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). In August 2013, Sanchez Energy Partners I, LP (“SEP I”), an affiliate of Sanchez Oil & Gas Corporation (“SOG”) , contributed certain oil and natural gas properties in Texas and Louisiana to CEP in exchange for equity interests in CEP. On May 8, 2014, the Company and SP Holdings, LLC (the “Manager”) , the sole member of our general partner, entered into a Shared Services Agreement (the “Services Agreement”) pursuant to which the Manager agreed to provide 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. The Services Agreement became effective as of July 1, 2014. CEP’s name was subsequently changed to Sanchez Production Partners LLC and 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 . T he 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.” SOG is a private company engaged in the management of oil and natural gas properties on behalf of its related companies, with whom it has various service agreements encompassing a wide range of activities, including, but not limited to, management, administrative and operational services. SEP I and SP Holdings, LLC are related to SOG through services agreements, and SOG owns a 0.5% general partner interest in SEP I. Our proved reserves are currently 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 . 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 assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities. 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	6 Months Ended
	Jun. 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, 201 4 . 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 June 30 , 2015 and December 31, 2014. Restricted Cash Restricted cash, as of June 30 , 2015 and December 31, 2014, of $ 0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of June 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 June 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	6 Months Ended
	Jun. 30, 2015
Acquisitions And Divestitures [Abstract]
Acquisitions And Divestitures	3. ACQUISITIONS AND DIVESTITURE S 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 Sanchez Energy Corporation (“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 (the “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 $ Pro Forma Operating Results The following pro forma combined results for the three and six months ended June 30, 2015 and 2014 reflect the consolidated results of operations of the Partnership as if the Eagle Ford acquisition and related financing 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, and paid-in-kind units issued in connection with the preferred units. The unaudited pro forma combined financial statements give effect to the events set forth below: • 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 Six Months Ended June 30, June 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 and diluted (1) $ - $ $ $ Net loss per unit after conversion Common units - Basic and 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 Eagle Ford acquisition 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 o f revenues over direct operating expenses included in the Partnership’s condensed consolidated statements of operations for the three and six months ended June 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 and Six Months Ended June 30, 2015 Revenues $ Excess of revenues over direct operating expenses $

Fair Value Messurements

Fair Value Messurements	6 Months Ended
	Jun. 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 tables summarize the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30 , 2015 and December 31, 2014 (in thousands): Fair Value Measurements at June 30, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral June 30, 2015 Derivative assets $ - $ $ - $ $ Derivative liabilities - - 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 Significant 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 June 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 June 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	6 Months Ended
	Jun. 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 June 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 three months ended June 30, 2015 and the year ended December 31, 2014 (in thousands): June 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 Loss in Income Location of Gain/(Loss) For the Three Months Ended June 30, For the Six Months Ended June 30, Derivative Type in Income 2015 2014 2015 2014 Commodity – Mark-to-Market Oil and natural gas sales $ $ $ $ Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently with three counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of June 30, 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 June 30, 2015, the fair value of the hedges assumed resulted in a less than $0.1 million asset in our condensed consolidated balance sheet.

Oil And Natural Gas Properties

Oil And Natural Gas Properties	6 Months Ended
	Jun. 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): June 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 six months ended June 30, 2015, we recorded non-cash charges of $0.9 million and $83.7 million, respectively, to impair the value of our Cherokee Basin properties, Woodford Shale properties and our Texas and Louisiana properties acquired prior to the Eagle Ford acquisition. For the three and six months ended June 30, 2014, we recorded non-cash charges of $0.1 million and $0.2 million, respectively, to impair the value of our Texas and Louisiana properties. The current impairment was primarily the result of a decline in commodity prices. 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 six months ended June 30, 2015 and 2014.

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 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 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 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 June 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. 0 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, 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, 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); (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); (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); 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. We monitor compliance with the covenants of the Credit Agreement on an ongoing basis. As of June 30, 2015, the Partnership's ratio of total net debt to Adjusted EBITDA, calculated in accordance with the terms of the Credit Agreement, exceeded 4.0 to 1.0. On August 12, 2015, the Partnership and its lenders executed a waiver and amendment that allows for the exclusion of approximately $1.4 million in non-recurring general and administrative expenses recorded in the second quarter 2015 for purposes of calculating the ratio of total net debt to Adjusted EBITDA for the quarter ended June 30, 2015 and each subsequent compliance period in which June 30, 2015 results would factor into the calculation of total net debt to Adjusted EBITDA. As a result of the waiver and amendment, the Partnership was deemed to be in compliance with the total net debt to Adjusted EBITDA covenant as of June 30, 2015 and currently forecasts that its ratio of total net debt to Adjusted EBITDA will not exceed 4.0 to 1.0 for the next twelve months. Debt Issuance Costs As of June 30, 2015, our unamortized debt issuance costs were $1.7 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	6 Months Ended
	Jun. 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 six months ended June 30, 2015 and the year ended December 31, 2014 were as follows (in thousands): June 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 June 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	6 Months Ended
	Jun. 30, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	9. COMMITMENTS AND CONTINGENCIES We did not have any material commitments and contingencies as of June 30, 2015.

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Related Party Transations	10. RELATED PARTY TRANSACTIONS Unit Ownership As of June 30, 2015, SEP I, an indirect subsidiary of SOG, owned 5,951,482 (approximately 595,148 common units after adjusting for reverse unit split) , or 18.9% of our common units, and a subsidiary of SN owned 1,052,632 (approximately 105,263 common units after adjusting for reverse unit split) , or 3.3% of our common units. Sanchez-Related Agreements On May 8, 2014, the Company and the Manager, an affiliate of SOG, entered into 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 six months ended June 30, 2015, we paid $2.4 million to the Manager under the Services Agreement, which included a prepayment of $0.5 million to be applied in the third quarter of 2015. Additionally, as of June 30, 2015 and December 31, 2014, the Partnership had a net receivable from related parties of $2.5 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 June 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. In August 2013, the Company entered into a Registration Rights Agreement with SEP I and 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 6, 2015, amendments to the Services Agreement and License Agreement were executed in order to replace the Company with the Partnership as counterparty to the agreements. No other material amendments have been made to the agreements mentioned herein. The amendments are attached as exhibits to this Quarterly Report on Form 10-Q. 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	6 Months Ended
	Jun. 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: Number of Weighted Average Restricted Grant Date Fair Units Value Per Unit Outstanding at December 31, 2014 10,082 $ 31.10 Granted 132,766 17.08 Vested (83,381) 18.79 Returned/Cancelled (33,826) 17.30 Outstanding at June 30, 2015 25,641 $ 16.50 During the three months ended June 30, 2015, the Partnership issued 38,860 restricted common units ( 3,886 common units after adjusting for reverse unit split) pursuant to the LTIP to one director of the Partnership’s general partner that vested immediately on the date of the grant. The unit based compensation expense for the award was based on its grant date fair value of $1.93 per unit ($ 19.30 per unit after adjusting for reverse unit split) (the closing price of the Partnership’s common units on the grant date). The remaining unvested units as of June 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 six months ended June 30, 2015.

Distributions To Unitholders

Distributions To Unitholders	6 Months Ended
	Jun. 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	6 Months Ended
	Jun. 30, 2015
Members' Equity/Partners' Capital [Abstract]
Members' Equity/Partners' Capital	13. MEMBERS’ EQUITY /PARTNERS’ CAPITAL Outstanding Units As of June 30, 2015, we had 10,859,375 Class A preferred units outstanding and 31,450,596 common units outstanding (approximately 3,145,060 common units after adjusting for reverse unit split) , which included 256,410 unvested restricted common units ( 25,641 common units after adjusting for reverse unit split) 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 The Partnership issued a total of 28,700 common units ( 2,870 common units after adjusting for reverse unit split) under its at-the-market facility during the three months ended June 30, 2015, for total net proceeds of less than $0.1 million. 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 (colle ctively, 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 plans to use 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 and distributed to the holders 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 - June 30 January 1 - March 6 June 30, June 30, 2015 2015 2015 2014 Class A units - Basic and diluted - - Class B Common units - Basic and diluted - - Common units - Basic and diluted - - Weighted Average basic and diluted units prior to reverse split Adjustment for reverse split Weighted Average basic and diluted units after reverse split At June 30 , 2015, we had 256,410 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 June 30, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): Total Common Units Assumed net loss attributable to common unitholders to be allocated March 6 - June 30 $ $ Basic and diluted loss per unit 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 June 30, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included non-cash impairment charges of $83.7 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 loss per unit for the three months ended June 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 $ $ The following table presents our basic and diluted loss per unit for the six months ended June 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	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	14. SUBSEQUENT EVENTS On August 3, 2015, the Partnership completed a 1-for-10 reverse split on its common units , pursuant to which c ommon 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.

Organization And Basis Of Pre23

Organization And Basis Of Presentation (Policies)	6 Months Ended
	Jun. 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 assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.
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)	6 Months Ended
	Jun. 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 June 30 , 2015 and December 31, 2014.
Restricted Cash	Restricted Cash Restricted cash, as of June 30 , 2015 and December 31, 2014, of $ 0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of June 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 June 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)	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 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 and diluted (1) $ - $ $ $ Net loss per unit after conversion Common units - Basic and diluted (1) $ $ - $ $ - (1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015. See Note 13.
Post-Acquisition Operating Results	Three and Six Months Ended June 30, 2015 Revenues $ Excess of revenues over direct operating expenses $

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements [Abstract]
Fair Value Of Assets And Liabilities On A Recurring Basis	The following tables summarize the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30 , 2015 and December 31, 2014 (in thousands): Fair Value Measurements at June 30, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral June 30, 2015 Derivative assets $ - $ $ - $ $ Derivative liabilities - - 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 Significant 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)	6 Months Ended
	Jun. 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	June 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 Loss in Income Location of Gain/(Loss) For the Three Months Ended June 30, For the Six Months Ended June 30, Derivative Type in Income 2015 2014 2015 2014 Commodity – Mark-to-Market Oil and natural gas sales $ $ $ $

Oil And Natural Gas Properties

Oil And Natural Gas Properties (Tables)	6 Months Ended
	Jun. 30, 2015
Oil And Natural Gas Properties [Abstract]
Oil and Natural Gas Properties	June 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)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation [Abstract]
Reconciliation of Asset Retirement Obligation	June 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)	6 Months Ended
	Jun. 30, 2015
Unit-Based Compensation [Abstract]
Schedule Of Units Granted	Number of Weighted Average Restricted Grant Date Fair Units Value Per Unit Outstanding at December 31, 2014 10,082 $ 31.10 Granted 132,766 17.08 Vested (83,381) 18.79 Returned/Cancelled (33,826) 17.30 Outstanding at June 30, 2015 25,641 $ 16.50

Members' Equity_Partners' Cap31

Members' Equity/Partners' Capital (Tables)	6 Months Ended
	Jun. 30, 2015
Members' Equity/Partners' Capital [Abstract]
Schedule Of Weighted Average Units Outstanding	Three Months Ended Three Months Ended March 6 - June 30 January 1 - March 6 June 30, June 30, 2015 2015 2015 2014 Class A units - Basic and diluted - - Class B Common units - Basic and diluted - - Common units - Basic and diluted - - Weighted Average basic and diluted units prior to reverse split Adjustment for reverse split Weighted Average basic and 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 June 30, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): Total Common Units Assumed net loss attributable to common unitholders to be allocated March 6 - June 30 $ $ Basic and diluted loss per unit 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 June 30, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included non-cash impairment charges of $83.7 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 loss per unit for the three months ended June 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 $ $ The following table presents our basic and diluted loss per unit for the six months ended June 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 $ $

Organization And Basis Of Pre32

Organization And Basis Of Presentation (Details)	Jun. 30, 2015
Sanchez Energy Partners I [Member] | Sanchez Oil And Gas Properties [Member]
Organization [Line Items]
Ownership percentage	0.50%

Summary Of Significant Accoun33

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Significant Accounting Policies [Line Items]
Restricted cash held in escrow	$ 600	$ 1,700
Allowance for doubtful accounts	400	200
Checks-In-Transit [Member]
Significant Accounting Policies [Line Items]
Cash	$ 0	$ 0

Acquisitions And Divestitures34

Acquisitions And Divestitures (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	Mar. 31, 2015	Jun. 30, 2015
Business Acquisition [Line Items]
Proceeds from issuance of preferred units		$ 17,375
Eagle Ford [Member]
Business Acquisition [Line Items]
Purchase price	$ 84,449
Adjusted purchase price	$ 83,378
Eagle Ford [Member] | Class A Preferred Units [Member]
Business Acquisition [Line Items]
Shares issued	10,625,000
Value of shares issued to Seller, per share	$ 1.60
SN [Member] | Eagle Ford [Member] | Class A Preferred Units [Member]
Business Acquisition [Line Items]
Shares issued prior to reverse split	1,052,632
Shares issued	105,263

Acquisitions And Divestitures35

Acquisitions And Divestitures (Estimated Values Of Assets Acquired And Liabilities Assumed) (Details) - Eagle Ford [Member] $ in Thousands	Mar. 31, 2015USD ($)
Business Acquisition [Line Items]
Proved developed reserves	$ 73,024
Facilities	8,017
Fair value of hedges assumed	3,408
Fair value of assets acquired	84,449
Asset retirement obligations	(877)
Ad valorem tax liability	(194)
Fair value of net assets acquired	$ 83,378

Acquisitions And Divestitures36

Acquisitions And Divestitures (Supplemental Pro Forma Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Revenue	$ 4,781	$ 25,715	$ 19,933	$ 50,728
Net gain (loss) attributable to common unitholders	$ (10,865)	$ 2,818	$ (101,316)	$ 7,307
Net gain (loss) per unit after conversion	$ (3.61)		$ (13.65)
Common Class A [Member]
Business Acquisition [Line Items]
Net gain (loss) prior to conversion, basic and filuted		$ 1.16	(24.89)	$ 1.40
Common Class B [Member]
Business Acquisition [Line Items]
Net gain (loss) prior to conversion, basic and filuted		$ 0.94	$ (19.80)	$ 2.44

Acquisitions And Divestitures37

Acquisitions And Divestitures (Post-Acquisition Operating Results) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Revenues	$ 4,781	$ 12,089	$ 16,705	$ 23,830
Eagle Ford [Member]
Business Acquisition [Line Items]
Revenues	3,328		3,328
Excess of revenue over direct operating expenses	$ 1,025		$ 1,025

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) - Recurring - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 15,860	$ 22,829
Derivative liabilities	(257)
Total net assets	15,603	22,829
Netting Cash And Collateral [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	(261)	(90)
Derivative liabilities	261	90
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	16,121	22,919
Derivative liabilities	(518)	(90)
Total net assets	$ 15,603	$ 22,829

Derivative And Financial Inst39

Derivative And Financial Instruments (Narrative) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Fair value of derivative instruments	$ 11,434	$ 14,671
Eagle Ford [Member]
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	$ 100

Derivative And Financial Inst40

Derivative And Financial Instruments (Summary Of Hedges In Place) (Details) - Jun. 30, 2015	MMBTU$ / MMBTUbbl
West Texas Intermediate 2015 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	118,097
Average Price	75.10
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	227,679
Average Price	75.37
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
Average Price	65.65
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	1,294,244
NYMEX 2015 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,171,767
Average Price	4.16
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	2,290,101
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	7,268,276

Derivative And Financial Inst41

Derivative And Financial Instruments (Schedule Of Change In Commodity Derivatives Fair Value) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives	$ 22,829	$ 22,829	$ 10,601
Ending fair value of commodity derivatives	15,603	$ 15,603	22,829
Crude Oil Derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains on derivatives	351		13,983
Net settlements on derivative contracts	(6,151)		69
Natural Gas Derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains on derivatives	1,992		5,871
Net settlements on derivative contracts	$ (3,418)		$ (7,695)

Derivative And Financial Inst42

Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Oil And Natural Gas Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative loss recognized in income	$ (5,897)	$ (4,730)	$ (1,064)	$ (8,805)

Oil And Natural Gas Propertie43

Oil And Natural Gas Properties (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Oil And Natural Gas Properties [Abstract]
Non-cash impairment charges	$ 862	$ 45	$ 83,727	$ 194
Exploration costs			$ 0	$ 0

Oil And Natural Gas Propertie44

Oil And Natural Gas Properties (Oil and Natural Gas Properties) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Oil And Natural Gas Properties [Abstract]
Proved property	$ 730,743	$ 649,432
Unproved property	1,583	1,560
Land	501	501
Total property costs	732,827	651,493
Materials and supplies	1,056	1,056
Total	733,883	652,549
Less: Accumulated depreciation, depletion, amortization and impairments	(606,607)	(517,239)
Oil and natural gas properties and equipment, net	$ 127,276	$ 135,310

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Line of Credit Facility [Line Items]
Amount of debt repaid		$ 42,500	$ 4,500
Outstanding debt under reserve-based credit facility	$ 106,000	106,000			$ 42,500
Unamortized debt issue costs	1,700	1,700			$ 700
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Reserve based credit facility maximum borrowing capacity				$ 500,000
Borrowing base amount	110,000	110,000
Amount borrowed under credit facility				106,000
Sub-limit of reserve-based credit facility		15,000
Outstanding debt under reserve-based 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%
Amount of general and administrative expenses excluded	$ 1,400
Second Amended And Restated Credit Agreement [Member]
Line of Credit Facility [Line Items]
Reserve based credit facility maximum borrowing capacity				350,000
Borrowing base amount				$ 70,000
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		90.00%
Debt to Adjusted EBITDA ratio	4	4
Minimum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Interest rate		1.75%
Minimum [Member] | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Interest rate		0.75%
Maximum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base		0.50%
Total Net Debt ratio		4
Maximum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Interest rate		2.75%
Maximum [Member] | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Interest rate		1.75%

Asset Retirement Obligation (Re

Asset Retirement Obligation (Reconciliation of Asset Retirement Obligation) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 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			(11)
Revisions to cost estimates					6,780
Settlements			(19)		(5)
Accretion expense	$ 264	$ 150	517	$ 300	604
Asset retirement obligation, ending balance	$ 18,395		$ 18,395		$ 17,031

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($)	6 Months Ended
	Jun. 30, 2015	Sep. 30, 2015	Mar. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Units owned by third party prior to reverse split	1,052,632
Units owned by third party	105,263
Units owned by third party, percentage of total shares	3.30%
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	$ 2,400,000
Net receivable from related parties	$ 2,500,000			$ 1,000,000
Scenario, Forecast [Member]
Related Party Transaction [Line Items]
Prepaid administrative fee		$ 500,000
Sanchez Energy Partners I [Member]
Related Party Transaction [Line Items]
Units owned by third party prior to reverse split	5,951,482
Units owned by third party	595,148
Units owned by third party, percentage of total shares	18.90%
Eagle Ford [Member]
Related Party Transaction [Line Items]
Purchase price			$ 84,449,000

Unit-Based Compensation (Narrat

Unit-Based Compensation (Narrative) (Details) - Jun. 30, 2015 - Restricted Stock Units (RSUs) [Member] - $ / shares	Total
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Restricted units issued prior to reverse split	38,860
Restricted units issued	3,886
Closing market price prior to reverse split	$ 1.93
Closing market price	$ 19.30

Unit-Based Compensation (Schedu

Unit-Based Compensation (Schedule Of Units Granted) (Details) - 6 months ended Jun. 30, 2015 - $ / shares	Total
Unit-Based Compensation [Abstract]
Number of Restricted Units, Outstanding	10,082
Number of Restricted Units, Granted	132,766
Number of Restricted Units, Vested	(83,381)
Number of Restricted Units, Returned/Cancelled	(33,826)
Number of Restricted Units, Outstanding	25,641
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$ 31.10
Weighted Averaged Grant Date Fair Value Per Unit, Granted	17.08
Weighted Averaged Grant Date Fair Value Per Unit, Vested	18.79
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled	17.30
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$ 16.50

Members' Equity_Partners' Cap50

Members' Equity/Partners' Capital (Narrative) (Details) - USD ($)	Apr. 15, 2015	Mar. 31, 2015	Mar. 06, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share units outstanding prior to reverse split				31,450,596		31,450,596
Share units outstanding				3,145,060		3,145,060
Percent of common units outstanding			2.00%
Common units issued prior to reverse split				28,700		28,700
Common units issued				2,870		2,870
Issuance of common units						$ 52,000
Proceeds from issuance of preferred units						$ 17,375,000
Restricted unvested common units granted and outstanding				25,641		25,641		10,082
Asset impairments				$ 862,000	$ 45,000	$ 83,727,000	$ 194,000
LTIP [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share units outstanding prior to reverse split				256,410		256,410
Share units outstanding				25,641		25,641
Class A Preferred Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred units outstanding				10,859,375		10,859,375		0
Preferred units sold				10,859,375		10,859,375		0
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%
Purchasers [Member] | Class A Preferred Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred units sold		10,625,000
Price per unit sold		$ 1.60
Proceeds from issuance of preferred units		$ 17,000,000
April Purchasers [Member] | Class A Preferred Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred units sold	234,375
Price per unit sold	$ 1.60
Proceeds from issuance of preferred units	$ 375,000

Members' Equity_Partners' Cap51

Members' Equity/Partners' Capital (Schedule Of Weighted Average Units Outstanding) (Details) - shares	2 Months Ended	3 Months Ended		4 Months Ended
	Mar. 05, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015
Class Of Stock [Line Items]
Weighted Average basic and diluted units prior to reverse split	29,276,131	31,134,285	28,789,885	30,874,312
Adjustment for reverse split	(26,348,518)	(28,020,857)	(25,910,896)	(27,786,881)
Weighted Average basic and diluted units after reverse split	2,927,613	3,113,428	2,878,989	3,087,431
Common Class A [Member]
Class Of Stock [Line Items]
Weighted Average basic and diluted units prior to reverse split	484,505		484,505
Common Class B [Member]
Class Of Stock [Line Items]
Weighted Average basic and diluted units prior to reverse split	28,791,626		28,305,380
Common Units [Member]
Class Of Stock [Line Items]
Weighted Average basic and diluted units prior to reverse split		31,134,285		30,874,312

Members' Equity_Partners' Cap52

Members' Equity/Partners' Capital (Earnings Per Common Unit Amounts) (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	3 Months Ended	4 Months Ended	6 Months Ended
	Mar. 05, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Class Of Stock [Line Items]
Assumed net loss to be allocated	$ (923)	$ (5,011)	$ (99,928)	$ (7,950)
Common Class A [Member]
Class Of Stock [Line Items]
Assumed net loss to be allocated	$ (18)	$ (100)		$ (159)
Basic and diluted loss per unit prior to reverse split	$ (0.04)	$ (0.21)		$ (0.15)
Basic and diluted loss per unit after reverse split	$ (0.38)	$ (2.07)		$ (1.52)
Common Class B [Member]
Class Of Stock [Line Items]
Assumed net loss to be allocated	$ (905)	$ (4,911)		$ (7,791)
Basic and diluted loss per unit prior to reverse split	$ (0.03)	$ (0.17)		$ (0.28)
Basic and diluted loss per unit after reverse split	$ (0.31)	$ (1.73)		$ (2.76)
Common Units [Member]
Class Of Stock [Line Items]
Assumed net loss to be allocated			$ (99,928)
Basic and diluted loss per unit prior to reverse split			$ (3.23)
Basic and diluted loss per unit after reverse split			$ (32.37)

Subsequent Events (Details)

Subsequent Events (Details)	Aug. 03, 2015
Subsequent Event [Member]
Subsequent Event [Line Items]
Number of common units received for every ten common units held	0.1