Evolve Transition Infrastructure (SNMP) 10-Q 15 May 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	15-May-15
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	FALSE
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Trading Symbol	spp
Entity Registrant Name	Sanchez Production Partners LP
Entity Central Index Key	1362705
Current Fiscal Year End Date	-19
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		31,383,036

Condensed_Consolidated_Stateme

Condensed Consolidated Statements Of Operations (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues
Natural gas sales	$6,574	$6,024
Oil and liquids sales	5,350	5,717
Total revenues	11,924	11,741
Operating expenses:
Lease operating expenses	4,900	5,120
Cost of sales	205	360
Production taxes	370	772
General and administrative	9,547	3,571
Gain on sale of assets	-59	-7
Depreciation, depletion and amortization	3,120	4,050
Asset impairments	82,865	149
Accretion expense	253	150
Total operating expenses	101,201	14,165
Other expenses (income)
Interest expense	646	525
Other expense (income)	63	-10
Total other expenses	709	515
Total expenses	101,910	14,680
Net loss	($89,986)	($2,939)
Earnings Per Share Basic And Diluted After Conversion [Abstract]
Common units - Basic and diluted	($2.98)
Earnings Per Share Basic And Diluted Other Disclosures, After Conversion [Abstract]
Common units - Basic and diluted	29,928,009
Common Class A [Member]
Net loss per unit prior to conversion
Net loss per unit - Basic and diluted	($0.04)	($0.04)
Weighted Average Units Outstanding
Weighted Average Units Outstanding - Basic and diluted	484,505	1,615,017
Common Class B [Member]
Net loss per unit prior to conversion
Net loss per unit - Basic and diluted	($0.03)	($0.10)
Weighted Average Units Outstanding
Weighted Average Units Outstanding - Basic and diluted	28,791,626	28,214,104

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Current assets
Cash and cash equivalents	$2,235	$4,238
Restricted cash	600	1,748
Accounts receivable, net	4,369	5,217
Prepaid expenses	2,071	1,783
Fair value of derivative instruments	16,001	14,671
Total current assets	25,276	27,657
Oil and natural gas properties and related equipment (successful efforts method)
Oil and natural gas properties, equipment and facilities	733,391	651,493
Material and supplies	1,056	1,056
Less accumulated depreciation, depletion, amortization, and impairments	-602,995	-517,239
Oil and natural gas properties and equipment, net	131,452	135,310
Other assets
Debt issuance costs	1,708	689
Fair value of derivative instruments	9,504	8,158
Other non-current assets	1,634	1,790
Total assets	169,574	173,604
Current liabilities
Accounts payable and accrued liabilities	8,227	6,116
Royalty payable	738	1,134
Total current liabilities	8,965	7,250
Other liabilities
Asset retirement obligation	18,150	17,031
Long-term debt	106,000	42,500
Total other liabilities	124,150	59,531
Total liabilities	133,115	66,781
Commitments and contingencies (See Note 9)
Members' equity / Partners' capital
Total members' equity/partners' capital	36,459	106,823
Total liabilities and members' equity/partners' capital	169,574	173,604
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	13,059
Common Units [Member]
Members' equity / Partners' capital
LP common units	$23,400

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical)	Mar. 31, 2015	Dec. 31, 2014
Common units outstanding	31,383,036
Common Class A [Member]
Share units issued	0	484,505
Common units outstanding	0	484,505
Common Class B [Member]
Share units issued	0	28,792,584
Common units outstanding	0	28,792,584
Class A Preferred Units [Member]
Preferred units issued	10,625,000	0
Preferred units outstanding	10,625,000	0
Common Units [Member]
LP common units, issued	31,383,036	0
LP common units, outstanding	31,383,036	0

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements Of Cash Flows (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net loss	($89,986)	($2,939)
Adjustments to reconcile net loss to cash provided by operating activities
Depreciation, depletion and amortization	3,120	4,050
Asset impairments	82,865	149
Amortization of debt issuance costs	239	59
Accretion expense	253	150
Equity earnings in affiliate	61	-12
Gain from disposition of property and equipment	-59	-7
Bad debt expense	112	93
Total mark-to-market (gains) losses on commodity derivative contracts	-4,832	4,074
Cash mark-to-market settlements on commodity derivative contracts	4,374	923
Unit-based compensation programs	1,992	101
Changes in Operating Assets and Liabilities:
(Increase) decrease in accounts receivable	1,926	-3,181
(Increase) decrease in prepaid expenses	-288	1,378
Decrease in other assets	2	2
Increase in accounts payable and accrued liabilities	2,173	1,359
Increase (decrease) in royalty payable	-396	263
Net cash provided by (used in) operating activities	1,556	6,462
Cash flows from investing activities:
Cash paid for acquisitions	-81,602
Development of natural gas properties	-954	-2,731
Proceeds from sale of property and equipment	84	58
Distributions from equity affiliate		100
Net cash used in investing activities	-82,472	-2,573
Cash flows from financing activities:
Proceeds from issuance of preferred units	17,000
Proceeds from issuance of debt	106,000
Repayment of debt	-42,500
Units tendered by employees for tax withholdings	-618	-157
Debt issuance costs	-969
Net cash provided by (used in) financing activities	78,913	-157
Net increase/decrease in cash and cash equivalents	-2,003	3,732
Cash and cash equivalents, beginning of period	4,238	4,894
Cash and cash equivalents, end of period	2,235	8,626
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	-149	-361
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	-405	-478
Cash paid during the period for income taxes	($2)	($2)

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements Of Changes In Members' Equity (USD $)	Common Class A [Member]	Common Class A [Member]	Common Class B [Member]	Common Class B [Member]	Class A Preferred Units [Member]	Common Units [Member]	Total
In Thousands, except Share data	Common Units [Member]		Common Units [Member]
Beginning Balance at Dec. 31, 2013		$2,591		$96,314			$98,905
Beginning Balance (in shares) at Dec. 31, 2013		1,615,017		28,462,185
Units tendered by employees for tax withholding (in shares)				-160,182
Units tendered by employees for tax withholding, cost				-415			-415
Unit-based compensation programs (in shares)				490,581
Unit-based compensation programs				1,298			1,298
Cancellation of units (in shares) (See Note 9)		-1,130,512
Cancellation of units		-851		-1,617			-2,468
Net income (loss)		190		9,313			9,503
Ending Balance at Dec. 31, 2014		1,930		104,893			106,823
Ending Balance (in shares) at Dec. 31, 2014		484,505		28,792,584
Units tendered by employees for tax withholding (in shares)				-15,570
Units tendered by employees for tax withholding, cost				21			21
Net income (loss)		-18		-905			-923
Ending Balance at Mar. 05, 2015		1,912		103,967			105,879
Ending Balance (in shares) at Mar. 05, 2015		484,505		28,777,014
Units tendered by employees for tax withholding (in shares)						-322,692
Units tendered by employees for tax withholding, cost						-597	-597
Unit-based compensation programs (in shares)						1,288,796
Unit-based compensation programs						1,993	1,993
Private placement of Class A Preferred Units (in shares)					10,625,000
Private placement of Class A Preferred Units					16,247		16,247
Beneficial conversion feature of Class A Preferred Units					-3,188	3,188
Units converted to LP Common Units upon limited partnerships (in shares)	587,286	-484,505	28,777,014	-28,777,014
Units converted to LP Common Units upon limited partnerships	1,912	-1,912	103,967	-103,967
Unit issued for acquisition of properties (in shares)						1,052,632
Unit issued for acquisition of properties						2,000	2,000
Net income (loss)						-89,063	-89,063
Ending Balance at Mar. 31, 2015					$13,059	$23,400	$36,459
Ending Balance (in shares) at Mar. 31, 2015					10,625,000	31,383,036

Organization_And_Basis_Of_Pres

Organization And Basis Of Presentation	3 Months Ended
	Mar. 31, 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 exploration 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, professionals 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. As of the March 6, 2015 conversion date, the Manager owns the general partner of SPP and all of SPP’s incentive distribution rights. Our common units are currently listed on the NYSE MKT under the symbol “SPP.”
	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_Account

Summary Of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2014.
	Cash
	All highly liquid investments with original maturities of three months or less are considered cash.  Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on.  There were no checks-in-transit reported in accounts payable at March 31, 2015 and December 31, 2014.
	Restricted  Cash
	Restricted cash, as of March 31, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow.  The balance as of March 31, 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 March 31, 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	3 Months Ended
	Mar. 31, 2015
Acquisitions And Divestitures [Abstract]
Acquisitions And Divestitures	3. ACQUISITIONS AND DIVESTITURES
	Eagle Ford Acquisition
	On March 31, 2015, we completed our 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 interest in the Eagle Ford properties will stay constant for the remainder of the respective lives of the assets.
	The adjusted purchase price of $83.6 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 to SN, borrowings under the Partnership’s Credit Agreement (as defined in Note 7, “Long-Term Debt”), and available cash.  The purchase price allocation for the Eagle Ford acquisition is preliminary and is subject to further adjustments and the settlement of certain post-closing adjustments with the seller. 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	$	73,226
	Facilities		8,039
	Fair value of hedges assumed		3,408
	Fair value of assets acquired		84,673
	Asset retirement obligations		-877
	Ad valorem tax liability		-194
	Fair value of net assets acquired	$	83,602
	Pro Forma Operating Results
	The following pro forma combined results for the three months ended March 31, 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
		March 31,
		2015		2014
	Revenues	$	15,153	$	25,013
	Net income (loss) attributable to common unitholders	$	-90,591	$	4,348
	Net income (loss) per unit prior to conversion
	Class A units - Basic and diluted	$	-2.49	$	0.05
	Class B units - Basic and diluted	$	-1.98	$	0.15
	Net loss per unit after conversion
	Common units - Basic and diluted	$	-1.01	$	-
	The 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 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 pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the pro forma combined financial information and actual results.

Fair_Value_Messurements

Fair Value Messurements	3 Months Ended
	Mar. 31, 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 March 31, 2015 and December 31, 2014 (in thousands):
		Fair Value Measurements at March 31, 2015
		Active Markets for		Observable
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Mar-15
	Derivative assets	$	-	$	25,505	$	-	$	-	$	25,505
	Derivative liabilities		-		-		-		-		-
	Total net assets	$	-	$	25,505	$	-	$	-	$	25,505
	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		31-Dec-14
	Derivative assets	$	-	$	22,919	$	-	$	-90	$	22,829
	Derivative liabilities		-		-90		-		90		-
	Total net assets	$	-	$	22,829	$	-	$	-	$	22,829
	As of March 31, 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 March 31, 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_Instr

Derivative And Financial Instruments	3 Months Ended
	Mar. 31, 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 March 31, 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						128,712		$	74.42	118,097	$	75.10	109,582	$	75.64	356,391	$	75.02
	2016	121,005		$	73.53		113,226		$	73.77	106,483	$	73.95	100,525	$	74.10	441,239	$	73.82
	2017	57,953		$	64.80		54,554		$	64.80	51,570	$	64.80	48,926	$	64.80	213,003	$	64.80
	2018	56,798		$	65.40		54,197		$	65.40	51,851	$	65.40	49,709	$	65.40	212,555	$	65.40
	2019	52,760		$	65.65		50,784		$	65.65	48,960	$	65.65	47,264	$	65.65	199,768	$	65.65
																	1,422,956
	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						1,239,273		$	4.15	1,171,767	$	4.16	1,118,334	$	4.17	3,529,374	$	4.16
	2016	1,098,689		$	4.13		1,048,146		$	4.14	998,394	$	4.14	963,327	$	4.14	4,108,556	$	4.14
	2017	80,563		$	3.52		75,829		$	3.52	71,672	$	3.52	67,984	$	3.52	296,048	$	3.52
	2018	79,042		$	3.58		75,404		$	3.58	72,115	$	3.58	69,122	$	3.58	295,683	$	3.58
	2019	73,432		$	3.62		70,648		$	3.62	68,088	$	3.62	65,720	$	3.62	277,888	$	3.62
																	8,507,549
	The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the three months ended March 31, 2015 and the year ended December 31, 2014 (in thousands):
		March 31,			December 31,
		2015			2014
	Beginning fair value of commodity derivatives	$	22,829		$	10,601
	Net gains on crude oil derivatives		2,643			13,983
	Net gains on natural gas derivatives		2,189			5,871
	Net settlements on derivative contracts:
	Crude oil		-4,023			69
	Natural gas		-1,541			-7,695
	Fair value of commodity derivatives received by novation:
	Crude oil		3,263			-
	Natural gas		145			-
	Ending fair value of commodity derivatives	$	25,505		$	22,829
	The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands):
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Three Months Ended March 31,
	Derivative Type		in Income		2015			2014
	Commodity – Mark-to-Market		Oil and natural gas sales		$	4,832		$	-4,074
	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 March 31, 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 March 31, 2015, the fair value of the hedges assumed resulted in a $3.4 million asset in our condensed consolidated balance sheet.

Oil_And_Natural_Gas_Properties

Oil And Natural Gas Properties	3 Months Ended
	Mar. 31, 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):
		March 31,		December 31,
		2015		2014
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property costs
	Proved property	$	731,308	$	649,432
	Unproved property		1,582		1,560
	Land		501		501
	Total property costs		733,391		651,493
	Materials and supplies		1,056		1,056
	Total		734,447		652,549
	Less: Accumulated depreciation, depletion, amortization and impairments		-602,995		-517,239
	Oil and natural gas properties and equipment, net	$	131,452	$	135,310
	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 months ended March 31, 2015, we recorded non-cash charges of $82.9 million 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 months ended March 31, 2014, we recorded a non-cash charge of $0.1 million 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 three months ended March 31, 2015 and 2014.

LongTerm_Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 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 March 31, 2015 was set at $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) senior secured net debt to consolidated Adjusted EBITDA for the last twelve months of not greater than 3.5 to 1.0 as of the last day of any fiscal quarter.
	The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events:  (i) 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 will be able to 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 reserve-based credit facility also permits us to hedge the interest rate on up to 75% of the then-outstanding principal amounts of our indebtedness for borrowed money.
	As of March 31, 2015, we were in compliance with the covenants of the Credit Agreement.  We monitor compliance on an on-going basis.
	Debt Issuance Costs
	As of March 31, 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	3 Months Ended
	Mar. 31, 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 three months ended March 31, 2015 and the year ended December 31, 2014 were as follows (in thousands):
		March 31,		December 31,
		2015		2014
	Asset retirement obligation, beginning balance	$	17,031	$	9,513
	Liabilities added from acquisitions		877		80
	Liabilities added from drilling		-		59
	Sold		-11		-
	Revisions to cost estimates		-		6,780
	Settlements				-5
	Accretion expense		253		604
	Asset retirement obligation, ending balance	$	18,150	$	17,031
	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 March 31, 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	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	9. COMMITMENTS AND CONTINGENCIES
	We did not have any material commitments and contingencies as of March 31, 2015.

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Related Party Transations	10. RELATED PARTY TRANSACTIONS
	Unit Ownership
	As of March 31, 2015, SEP I, an indirect subsidiary of SOG, owned 5,951,482, or 19.0%, of our common units and a subsidiary of SN owned 1,052,632, or 3.4%, 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.  In connection with providing the services under the Services Agreement, the Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) 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 three months ended March 31, 2015, we paid $0.9 million to the Manager under the Services Agreement.
	Additionally, as of March 31, 2015 and December 31, 2014, the Partnership had a net receivable from related parties of $0.2 million and $0.9 million, respectively, which are included in “Accounts receivable, net” and “Accounts payable and accrued liabilities” in the condensed consolidated balance sheets. The net receivables as of March 31, 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.”

UnitBased_Compensation

Unit-Based Compensation	3 Months Ended
	Mar. 31, 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 is presented in the following table:
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2014	100,825	$	3.11
	Granted	1,288,796		1.7
	Vested	-794,949		1.86
	Returned/Cancelled	-338,262		1.73
	Outstanding at March 31, 2015	256,410	$	1.65
	The remaining unvested units as of March 31, 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 three months ended March 31, 2015.

Distributions_To_Unitholders

Distributions To Unitholders	3 Months Ended
	Mar. 31, 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_EquityPartners_Capital

Members' Equity/Partners' Capital	3 Months Ended
	Mar. 31, 2015
Members' Equity/Partners' Capital [Abstract]
Members' Equity/Partners' Capital	13. MEMBERS’ EQUITY/PARTNERS’ CAPITAL
	Outstanding Units
	As of March 31, 2015, we had 10,625,000 Class A preferred units outstanding and 31,383,036 common units outstanding, which included 256,410 unvested restricted common units issued under the LTIP.
	Conversion
	The Company’s board of managers approved a Plan of Conversion (the “Conversion”) providing for the Conversion of the Company from a limited liability company formed under the laws of the State of Delaware into Sanchez LP, a limited partnership formed under the laws of the State of Delaware. This plan was approved by the vote of the unitholders of the Company on March 6, 2015. After the Conversion, all of the rights, privileges and obligations of the Company prior to the Conversion were transferred and are now held by the Partnership. The Conversion converted each outstanding common unit of the Company into one common unit of the Partnership. The outstanding Class A units of the Company were converted into common units of the Partnership in a number equal to 2% of the Partnership’s common units outstanding immediately after the Conversion (after taking into account the conversion of such Class A units), and the outstanding Class Z unit of the Company was cancelled. In addition, a non-economic general partner interest in the Partnership was issued to our general partner, and the incentive distribution rights of the Partnership were issued to the Manager.
	Preferred Unit Issuance
	Class A Preferred Unit Offering: 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.
	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:
			March 6 - March 31		January 1 - March 6		March 31,
			2015		2015		2014
	Class A units - Basic and diluted		-		484,505		1,615,017
	Class B Common units - Basic and diluted		-		28,791,626		28,214,104
	Common units - Basic and diluted		29,928,009		-		-
	Weighted Average basic and diluted units		29,928,009		29,276,131		29,829,121
	At March 31, 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	$	-923	$	-18	$	-905
	Basic and diluted loss per unit			$	-0.04	$	-0.03
	The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through March 31, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts):
		Total		Common Units
	Assumed net loss to be allocated March 6 - March 31	$	-89,063	$	-89,063
	Basic and diluted loss per unit			$	-2.98
	Net loss per unit increased significantly for the period from March 6, 2015 through March 31, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included a non-cash impairment charge of $82.9 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 March 31, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Assumed net loss to be allocated	$	-2,939	$	-59	$	-2,880
	Basic and diluted loss per unit			$	-0.04	$	-0.1

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	14. SUBSEQUENT EVENTS
	On April 15, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement (the “April Preferred Unit Purchase Agreement”) with the purchasers named on Schedule A thereto (collectively, the “ April Purchasers”), pursuant to which the Partnership sold, and the April Purchasers purchased, 234,375 of the Partnership’s Class A Preferred Units in a privately negotiated transaction for an aggregate cash purchase price of $1.60 per Class A Preferred Unit resulting in gross proceeds to the Partnership of $375,000.  The Partnership plans to use the proceeds for general working capital purposes.

Organization_And_Basis_Of_Pres1

Organization And Basis Of Presentation (Policies)	3 Months Ended
	Mar. 31, 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_Account1

Summary Of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 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 March 31, 2015 and December 31, 2014.
Restricted Cash	Restricted  Cash
	Restricted cash, as of March 31, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow.  The balance as of March 31, 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 March 31, 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)	3 Months Ended
	Mar. 31, 2015
Acquisitions And Divestitures [Abstract]
Estimated Values Of Assets Acquired And Liabilities Assumed
	Proved developed reserves	$	73,226
	Facilities		8,039
	Fair value of hedges assumed		3,408
	Fair value of assets acquired		84,673
	Asset retirement obligations		-877
	Ad valorem tax liability		-194
	Fair value of net assets acquired	$	83,602
Supplemental Pro Forma Information
		Three Months Ended
		March 31,
		2015		2014
	Revenues	$	15,153	$	25,013
	Net income (loss) attributable to common unitholders	$	-90,591	$	4,348
	Net income (loss) per unit prior to conversion
	Class A units - Basic and diluted	$	-2.49	$	0.05
	Class B units - Basic and diluted	$	-1.98	$	0.15
	Net loss per unit after conversion
	Common units - Basic and diluted	$	-1.01	$	-

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2015 and December 31, 2014 (in thousands):
		Fair Value Measurements at March 31, 2015
		Active Markets for		Observable
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Mar-15
	Derivative assets	$	-	$	25,505	$	-	$	-	$	25,505
	Derivative liabilities		-		-		-		-		-
	Total net assets	$	-	$	25,505	$	-	$	-	$	25,505
	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		31-Dec-14
	Derivative assets	$	-	$	22,919	$	-	$	-90	$	22,829
	Derivative liabilities		-		-90		-		90		-
	Total net assets	$	-	$	22,829	$	-	$	-	$	22,829

Derivative_And_Financial_Instr1

Derivative And Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 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						128,712		$	74.42	118,097	$	75.10	109,582	$	75.64	356,391	$	75.02
	2016	121,005		$	73.53		113,226		$	73.77	106,483	$	73.95	100,525	$	74.10	441,239	$	73.82
	2017	57,953		$	64.80		54,554		$	64.80	51,570	$	64.80	48,926	$	64.80	213,003	$	64.80
	2018	56,798		$	65.40		54,197		$	65.40	51,851	$	65.40	49,709	$	65.40	212,555	$	65.40
	2019	52,760		$	65.65		50,784		$	65.65	48,960	$	65.65	47,264	$	65.65	199,768	$	65.65
																	1,422,956
	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						1,239,273		$	4.15	1,171,767	$	4.16	1,118,334	$	4.17	3,529,374	$	4.16
	2016	1,098,689		$	4.13		1,048,146		$	4.14	998,394	$	4.14	963,327	$	4.14	4,108,556	$	4.14
	2017	80,563		$	3.52		75,829		$	3.52	71,672	$	3.52	67,984	$	3.52	296,048	$	3.52
	2018	79,042		$	3.58		75,404		$	3.58	72,115	$	3.58	69,122	$	3.58	295,683	$	3.58
	2019	73,432		$	3.62		70,648		$	3.62	68,088	$	3.62	65,720	$	3.62	277,888	$	3.62
																	8,507,549
Schedule Of Change In Commodity Derivatives Fair Value
		March 31,			December 31,
		2015			2014
	Beginning fair value of commodity derivatives	$	22,829		$	10,601
	Net gains on crude oil derivatives		2,643			13,983
	Net gains on natural gas derivatives		2,189			5,871
	Net settlements on derivative contracts:
	Crude oil		-4,023			69
	Natural gas		-1,541			-7,695
	Fair value of commodity derivatives received by novation:
	Crude oil		3,263			-
	Natural gas		145			-
	Ending fair value of commodity derivatives	$	25,505		$	22,829
Schedule Of Effect Of Derivative Instruments On Condensed Consolidated Statements Of Operations
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Three Months Ended March 31,
	Derivative Type		in Income		2015			2014
	Commodity – Mark-to-Market		Oil and natural gas sales		$	4,832		$	-4,074

Oil_And_Natural_Gas_Properties1

Oil And Natural Gas Properties (Tables)	3 Months Ended
	Mar. 31, 2015
Oil And Natural Gas Properties [Abstract]
Oil and Natural Gas Properties
		March 31,		December 31,
		2015		2014
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property costs
	Proved property	$	731,308	$	649,432
	Unproved property		1,582		1,560
	Land		501		501
	Total property costs		733,391		651,493
	Materials and supplies		1,056		1,056
	Total		734,447		652,549
	Less: Accumulated depreciation, depletion, amortization and impairments		-602,995		-517,239
	Oil and natural gas properties and equipment, net	$	131,452	$	135,310

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation [Abstract]
Reconciliation of Asset Retirement Obligation
		March 31,		December 31,
		2015		2014
	Asset retirement obligation, beginning balance	$	17,031	$	9,513
	Liabilities added from acquisitions		877		80
	Liabilities added from drilling		-		59
	Sold		-11		-
	Revisions to cost estimates		-		6,780
	Settlements				-5
	Accretion expense		253		604
	Asset retirement obligation, ending balance	$	18,150	$	17,031

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2015
Unit-Based Compensation [Abstract]
Schedule Of Units Granted
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2014	100,825	$	3.11
	Granted	1,288,796		1.7
	Vested	-794,949		1.86
	Returned/Cancelled	-338,262		1.73
	Outstanding at March 31, 2015	256,410	$	1.65

Members_EquityPartners_Capital1

Members' Equity/Partners' Capital (Tables)	3 Months Ended
	Mar. 31, 2015
Members' Equity/Partners' Capital [Abstract]
Schedule Of Weighted Average Units Outstanding
			March 6 - March 31		January 1 - March 6		March 31,
			2015		2015		2014
	Class A units - Basic and diluted		-		484,505		1,615,017
	Class B Common units - Basic and diluted		-		28,791,626		28,214,104
	Common units - Basic and diluted		29,928,009		-		-
	Weighted Average basic and diluted units		29,928,009		29,276,131		29,829,121
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	$	-923	$	-18	$	-905
	Basic and diluted loss per unit			$	-0.04	$	-0.03
	The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through March 31, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts):
		Total		Common Units
	Assumed net loss to be allocated March 6 - March 31	$	-89,063	$	-89,063
	Basic and diluted loss per unit			$	-2.98
	Net loss per unit increased significantly for the period from March 6, 2015 through March 31, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included a non-cash impairment charge of $82.9 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 March 31, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Assumed net loss to be allocated	$	-2,939	$	-59	$	-2,880
	Basic and diluted loss per unit			$	-0.04	$	-0.1

Organization_And_Basis_Of_Pres2

Organization And Basis Of Presentation (Details) (Sanchez Energy Partners I [Member], Sanchez Oil And Gas Properties [Member])	Mar. 31, 2015
Sanchez Energy Partners I [Member] | Sanchez Oil And Gas Properties [Member]
Organization [Line Items]
Ownership percentage	0.50%

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Summary Of Significant Accounting Policies [Abstract]
Restricted cash held in escrow	$0.60	$1.70
Allowance for doubtful accounts	$0.40	$0.20

Acquisitions_And_Divestitures_1

Acquisitions And Divestitures (Narrative) (Details) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Mar. 31, 2015
Business Acquisition [Line Items]
Proceeds from issuance of preferred units	$17,000,000
Eagle Ford [Member]
Business Acquisition [Line Items]
Purchase price	84,673,000	84,673,000
Adjusted purchase price	83,602,000	83,602,000
Eagle Ford [Member] | Class A Preferred Units [Member]
Business Acquisition [Line Items]
Shares issued		10,625,000
Value of shares issued to Seller	$1.60	$1.60
SN [Member] | Eagle Ford [Member] | Class A Preferred Units [Member]
Business Acquisition [Line Items]
Shares issued		1,052,632

Acquisitions_And_Divestitures_2

Acquisitions And Divestitures (Estimated Values Of Assets Acquired And Liabilities Assumed) (Details) (Eagle Ford [Member], USD $)	Mar. 31, 2015
In Thousands, unless otherwise specified
Eagle Ford [Member]
Business Acquisition [Line Items]
Proved developed reserves	$73,226
Facilities	8,039
Fair value of hedges assumed	3,408
Fair value of assets acquired	84,673
Asset retirement obligations	-877
Fair value of net assets acquired	-194
Fair value of net assets acquired	$83,602

Acquisitions_And_Divestitures_3

Acquisitions And Divestitures (Supplemental Pro Forma Information) (Details) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Business Acquisition [Line Items]
Revenue	$15,153	$25,013
Net income (loss) attributable to common unitholders	($90,591)	$4,348
Net loss per unit after conversion	($1.01)
Common Class A [Member]
Business Acquisition [Line Items]
Net income (loss) prior to conversion	($2.49)	$0.05
Common Class B [Member]
Business Acquisition [Line Items]
Net income (loss) prior to conversion	($1.98)	$0.15

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$25,505	$22,829
Total net assets	25,505	22,829
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	25,505	22,919
Derivative liabilities		-90
Total net assets	25,505	22,829
Netting Cash And Collateral [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		-90
Derivative liabilities		$90

Derivative_And_Financial_Instr2

Derivative And Financial Instruments (Narrative) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
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	$16,001	$14,671
Eagle Ford [Member]
Derivative [Line Items]
Fair value of derivative instruments	$3,400

Derivative_And_Financial_Instr3

Derivative And Financial Instruments (Summary Of Hedges In Place) (Details)	3 Months Ended
	Mar. 31, 2015
	bbl
West Texas Intermediate 2015 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	128,712
Average Price	74.42
West Texas Intermediate 2015 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	118,097
Average Price	75.1
West Texas Intermediate 2015 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	109,582
Average Price	75.64
West Texas Intermediate 2015 [Member]
Derivative [Line Items]
Volume (in Bbls)	356,391
Average Price	75.02
West Texas Intermediate 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	121,005
Average Price	73.53
West Texas Intermediate 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	113,226
Average Price	73.77
West Texas Intermediate 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	106,483
Average Price	73.95
West Texas Intermediate 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	100,525
Average Price	74.1
West Texas Intermediate 2016 [Member]
Derivative [Line Items]
Volume (in Bbls)	441,239
Average Price	73.82
West Texas Intermediate 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	57,953
Average Price	64.8
West Texas Intermediate 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	54,554
Average Price	64.8
West Texas Intermediate 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	51,570
Average Price	64.8
West Texas Intermediate 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	48,926
Average Price	64.8
West Texas Intermediate 2017 [Member]
Derivative [Line Items]
Volume (in Bbls)	213,003
Average Price	64.8
West Texas Intermediate 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	56,798
Average Price	65.4
West Texas Intermediate 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	54,197
Average Price	65.4
West Texas Intermediate 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	51,851
Average Price	65.4
West Texas Intermediate 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	49,709
Average Price	65.4
West Texas Intermediate 2018 [Member]
Derivative [Line Items]
Volume (in Bbls)	212,555
Average Price	65.4
West Texas Intermediate 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls)	52,760
Average Price	65.65
West Texas Intermediate 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls)	50,784
Average Price	65.65
West Texas Intermediate 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls)	48,960
Average Price	65.65
West Texas Intermediate 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls)	47,264
Average Price	65.65
West Texas Intermediate 2019 [Member]
Derivative [Line Items]
Volume (in Bbls)	199,768
Average Price	65.65
West Texas Intermediate [Member]
Derivative [Line Items]
Volume (in Bbls)	1,422,956
NYMEX 2015 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu)	1,239,273
Average Price	4.15
NYMEX 2015 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu)	1,171,767
Average Price	4.16
NYMEX 2015 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu)	1,118,334
Average Price	4.17
NYMEX 2015 [Member]
Derivative [Line Items]
Volume (in MMBtu)	3,529,374
Average Price	4.16
NYMEX 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu)	1,098,689
Average Price	4.13
NYMEX 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu)	1,048,146
Average Price	4.14
NYMEX 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu)	998,394
Average Price	4.14
NYMEX 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu)	963,327
Average Price	4.14
NYMEX 2016 [Member]
Derivative [Line Items]
Volume (in MMBtu)	4,108,556
Average Price	4.14
NYMEX 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu)	80,563
Average Price	3.52
NYMEX 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu)	75,829
Average Price	3.52
NYMEX 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu)	71,672
Average Price	3.52
NYMEX 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu)	67,984
Average Price	3.52
NYMEX 2017 [Member]
Derivative [Line Items]
Volume (in MMBtu)	296,048
Average Price	3.52
NYMEX 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu)	79,042
Average Price	3.58
NYMEX 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu)	75,404
Average Price	3.58
NYMEX 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu)	72,115
Average Price	3.58
NYMEX 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu)	69,122
Average Price	3.58
NYMEX 2018 [Member]
Derivative [Line Items]
Volume (in MMBtu)	295,683
Average Price	3.58
NYMEX 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu)	73,432
Average Price	3.62
NYMEX 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu)	70,648
Average Price	3.62
NYMEX 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu)	68,088
Average Price	3.62
NYMEX 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu)	65,720
Average Price	3.62
NYMEX 2019 [Member]
Derivative [Line Items]
Volume (in MMBtu)	277,888
Average Price	3.62
NYMEX [Member]
Derivative [Line Items]
Volume (in MMBtu)	8,507,549

Derivative_And_Financial_Instr4

Derivative And Financial Instruments (Schedule Of Change In Commodity Derivatives Fair Value) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives			$22,829	$10,601
Ending fair value of commodity derivatives	25,505	22,829	22,829	10,601
Crude Oil Derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains on derivatives	2,643	13,983
Net settlements on derivative contracts	-4,023	69
Fair value of commodity derivatives received by novation	3,263
Natural Gas Derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains on derivatives	2,189	5,871
Net settlements on derivative contracts	-1,541	-7,695
Fair value of commodity derivatives received by novation	$145

Derivative_And_Financial_Instr5

Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) (Oil And Natural Gas Sales [Member], USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Oil And Natural Gas Sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gains (losses) recognized in income	$4,832	($4,074)

Oil_And_Natural_Gas_Properties2

Oil And Natural Gas Properties (Narrative) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Oil And Natural Gas Properties [Abstract]
Asset Impairments	$82,865	$149
Exploration costs	$0	$0

Oil_And_Natural_Gas_Properties3

Oil And Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Oil And Natural Gas Properties [Abstract]
Proved property	$731,308	$649,432
Unproved property	1,582	1,560
Land	501	501
Total property costs	733,391	651,493
Materials and supplies	1,056	1,056
Total	734,447	652,549
Less: Accumulated depreciation, depletion, amortization and impairments	-602,995	-517,239
Oil and natural gas properties and equipment, net	$131,452	$135,310

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Outstanding debt under reserve-based credit facility	$106,000,000	$42,500,000
Unamortized debt issue costs	1,700,000	700,000
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Reserve based credit facility maximum borrowing capacity	500,000,000
Borrowing base amount	110,000,000
Amount borrowed under credit facility	106,000,000
Sub-limit of reserve-based credit facility	15,000,000
Outstanding debt under reserve-based credit facility	106,000,000
Projected monthly production from proved reserves, first 24 months	90.00%
Projected monthly production from proved developed and producing reserves	90.00%
Projected monthly production from proved reserves, following 24 month period	85.00%
Projected monthly production from proved developed and producing reserves, following 12 month period	85.00%
Projected monthly production from proved reserves following 12 month period	80.00%
Maximum term on hedge	5 years
Maximum hedge on interest rate	75.00%
Second Amended And Restated Credit Agreement [Member]
Line of Credit Facility [Line Items]
Reserve based credit facility maximum borrowing capacity	350,000,000
Borrowing base amount	70,000,000
Outstanding debt under reserve-based credit facility	$42,500,000
Minimum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base	0.38%
Consolidated current asset ratio	1
Ownership percentage by subsidiary	50.00%
Exceeding of reserve-based credit facility over borrowing base	90.00%
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	3.5
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 $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 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			-5
Accretion expense	253	150	604
Asset retirement obligation, ending balance	$18,150		$17,031

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Related Party Transaction [Line Items]
Units owned by third party	1,052,632
Units owned by third party, percentage of total shares	3.40%
Percent of value of properties held used to compute quarterly fee	0.38%
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	900,000
Net receivable from related parties	200,000	900,000
Sanchez Energy Partners I [Member]
Related Party Transaction [Line Items]
Units owned by third party	5,951,482
Units owned by third party, percentage of total shares	19.00%
Eagle Ford [Member]
Related Party Transaction [Line Items]
Purchase price	$84,673,000

UnitBased_Compensation_Schedul

Unit-Based Compensation (Schedule Of Units Granted) (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Unit-Based Compensation [Abstract]
Number of Restricted Units, Outstanding	100,825
Number of Restricted Units, Granted	1,288,796
Number of Restricted Units, Vested	-794,949
Number of Restricted Units, Returned/Cancelled	-338,262
Number of Restricted Units, Outstanding	256,410
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$3.11
Weighted Averaged Grant Date Fair Value Per Unit, Granted	$1.70
Weighted Averaged Grant Date Fair Value Per Unit, Vested	$1.86
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled	$1.73
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$1.65

Members_EquityPartners_Capital2

Members' Equity/Partners' Capital (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended		0 Months Ended
	Mar. 06, 2015	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2015	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units outstanding		31,383,036		31,383,036
Percent of common units outstanding	2.00%
Proceeds from issuance of preferred units		$17,000,000
Restricted unvested common units granted and outstanding		256,410		256,410	100,825
Asset impairments		82,865,000	149,000
Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units outstanding		256,410		256,410
Class A Preferred Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred units outstanding		10,625,000		10,625,000	0
Preferred units sold		10,625,000		10,625,000	0
Common Class A [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units outstanding		0		0	484,505
Common Class B [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units outstanding		0		0	28,792,584
Purchasers [Member] | Class A Preferred Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred units sold		10,625,000		10,625,000
Price per unit sold		$1.60		$1.60
Proceeds from issuance of preferred units				$17,000,000

Members_EquityPartners_Capital3

Members' Equity/Partners' Capital (Schedule Of Weighted Average Units Outstanding) (Details)	1 Months Ended	2 Months Ended	3 Months Ended
	Mar. 31, 2015	Mar. 05, 2015	Mar. 31, 2014
Class Of Stock [Line Items]
Weighted average units outstanding - Basic and Diluted	29,276,131	29,928,009	29,829,121
Common Class A [Member]
Class Of Stock [Line Items]
Weighted average units outstanding - Basic and Diluted	484,505		1,615,017
Common Class B [Member]
Class Of Stock [Line Items]
Weighted average units outstanding - Basic and Diluted	28,791,626		28,214,104
Common Units [Member]
Class Of Stock [Line Items]
Weighted average units outstanding - Basic and Diluted		29,928,009

Members_EquityPartners_Capital4

Members' Equity/Partners' Capital (Earnings Per Common Unit Amounts) (Details) (USD $)	1 Months Ended	2 Months Ended	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 05, 2015	Mar. 31, 2014
Class Of Stock [Line Items]
Loss from continuing operations	($89,063)	($923)	($2,939)
Common Class A [Member]
Class Of Stock [Line Items]
Loss from continuing operations		-18	-59
Basic and diluted loss per unit		($0.04)	($0.04)
Common Class B [Member]
Class Of Stock [Line Items]
Loss from continuing operations		-905	-2,880
Basic and diluted loss per unit		($0.03)	($0.10)
Common Units [Member]
Class Of Stock [Line Items]
Loss from continuing operations	($89,063)
Basic and diluted loss per unit	($2.98)

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Apr. 15, 2015	Dec. 31, 2014
Subsequent Event [Line Items]
Proceeds from issuance of preferred units	$17,000,000
Class A Preferred Units [Member]
Subsequent Event [Line Items]
Preferred units sold	10,625,000		0
Class A Preferred Units [Member] | Subsequent Event [Member] | April Purchasers [Member]
Subsequent Event [Line Items]
Preferred units sold		234,375
Price per unit sold		$1.60
Proceeds from issuance of preferred units		$375,000