Evolve Transition Infrastructure (SNMP) 10-Q 13 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Nov. 10, 2014
Document And Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'spp	'
Entity Registrant Name	'Sanchez Production Partners LLC	'
Entity Central Index Key	'0001362705	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Smaller Reporting Company	'
Entity Common Stock, Shares Outstanding	'	28,735,703

Condensed_Consolidated_Stateme

Condensed Consolidated Statements Of Operations And Comprehensive Income (Loss) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues	'	'	'	'
Natural gas sales	$9,153	$7,328	$21,752	$18,745
Oil sales	11,402	4,680	21,784	13,497
Liquid sales	841	123	1,690	377
Total revenues (See Note 5)	21,396	12,131	45,226	32,619
Operating expenses:	'	'	'	'
Lease operating expenses	5,296	5,191	15,598	13,332
Cost of sales	404	323	1,198	1,122
Production taxes	796	731	2,563	1,840
General and administrative	3,780	3,015	12,942	11,156
(Gain)/Loss on sale of assets	'	31	-23	8
Depreciation, depletion and amortization	4,836	5,491	13,206	15,056
Asset impairments	43	'	237	'
Accretion expense	151	163	451	409
Total operating expenses	15,306	14,945	46,172	42,923
Other expense (income)	'	'	'	'
Interest expense	511	420	1,569	2,636
Other income	-76	23	-220	-149
Total other expenses	435	443	1,349	2,487
Total expenses	15,741	15,388	47,521	45,410
Income (loss) from continuing operations	5,655	-3,257	-2,295	-12,791
Loss from discontinued operations	'	'	'	-2,686
Net income (loss)	5,655	-3,257	-2,295	-15,477
Weighted Average Units Outstanding	'	'	'	'
Weighted Average Units Outstanding - Basic	29,037,073	27,207,634	29,215,792	24,942,162
Distributions declared and paid per unit	'	'	'	'
Common Class A [Member]	'	'	'	'
Other expense (income)	'	'	'	'
Income (loss) from continuing operations	'	-65	'	-256
Loss from discontinued operations	'	'	'	-54
Net income (loss)	113	-65	-46	-310
Earnings (loss) from continuing operations per unit	'	'	'	'
Continuing operations - Basic	$0.23	($0.06)	($0.05)	($0.36)
Continuing operations - Diluted	$0.23	($0.06)	($0.05)	($0.36)
Loss from discontinued operations per unit	'	'	'	'
Discontinued operations per unit - Basic and diluted	'	'	'	($0.08)
Net earnings (loss) per unit	'	'	'	'
Earnings (loss) per unit - Basic	$0.23	($0.06)	($0.05)	($0.44)
Earnings (loss) per unit - Diluted	$0.23	($0.06)	($0.05)	($0.44)
Weighted Average Units Outstanding	'	'	'	'
Weighted Average Units Outstanding - Basic	484,505	1,135,725	857,201	703,883
Weighted Average Units Outstanding - Diluted	484,505	1,135,725	857,201	703,883
Common Class B [Member]	'	'	'	'
Other expense (income)	'	'	'	'
Income (loss) from continuing operations	'	-3,192	'	-12,535
Loss from discontinued operations	'	'	'	-2,632
Net income (loss)	$5,542	($3,192)	($2,249)	($15,167)
Earnings (loss) from continuing operations per unit	'	'	'	'
Continuing operations - Basic	$0.19	($0.12)	($0.08)	($0.52)
Continuing operations - Diluted	$0.19	($0.12)	($0.08)	($0.52)
Loss from discontinued operations per unit	'	'	'	'
Discontinued operations per unit - Basic and diluted	'	'	'	($0.11)
Net earnings (loss) per unit	'	'	'	'
Earnings (loss) per unit - Basic	$0.19	($0.12)	($0.08)	($0.63)
Earnings (loss) per unit - Diluted	$0.19	($0.12)	($0.08)	($0.63)
Weighted Average Units Outstanding	'	'	'	'
Weighted Average Units Outstanding - Basic	28,552,568	26,071,909	28,358,591	24,238,279
Weighted Average Units Outstanding - Diluted	28,660,878	26,071,909	28,358,591	24,238,279

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$9,671	$4,894
Restricted cash (See Note 2)	1,748	'
Accounts receivable, net (See Note 2)	6,958	6,678
Prepaid expenses	1,678	2,547
Risk management assets (See Note 5)	4,528	9,141
Total current assets	24,583	23,260
Oil and natural gas properties (See Note 6)	'	'
Oil and natural gas properties, equipment and facilities	645,222	639,156
Material and supplies	1,056	1,054
Less accumulated depreciation, depletion, amortization, and impairments	-508,208	-495,215
Net oil and natural gas properties	138,070	144,995
Other assets	'	'
Debt issue costs (net of accumulated amortization of $9,075 and $9,003, respectively)	761	824
Risk management assets (See Note 5)	1,001	1,461
Restricted cash (See Note 2)	'	1,748
Other non-current assets	1,917	2,245
Total assets	166,332	174,533
Current liabilities	'	'
Accounts payable	75	12
Accrued liabilities	7,862	12,763
Royalty payable	1,172	1,242
Risk management liabilities (see Note 5)	245	'
Total current liabilities	9,354	14,017
Other liabilities	'	'
Asset retirement obligation	10,085	9,513
Other non-current liabilities	'	1,398
Debt (See Note 7)	51,950	50,700
Total other liabilities	62,035	61,611
Total liabilities	71,389	75,628
Commitments and contingencies (See Note 9)	'	'
Members' equity	'	'
Total members' equity	94,943	98,905
Total liabilities and members' equity	166,332	174,533
Common Class A [Member]	'	'
Members' equity	'	'
Limited partners' capital account	1,694	2,591
Common Class B [Member]	'	'
Members' equity	'	'
Limited partners' capital account	$93,249	$96,314

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Debt issue costs, accumulated amortization	$9,075	$9,003
Common Class A [Member]	'	'
Share units authorized	484,505	1,615,017
Share units issued	484,505	1,615,017
Shares units outstanding	484,505	1,615,017
Common Class B [Member]	'	'
Share units authorized	28,848,785	28,848,785
Share units issued	28,735,703	28,462,185
Shares units outstanding	28,735,703	28,462,185

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements Of Cash Flows (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities:	'	'
Net loss	($2,295)	($15,477)
Adjustments to reconcile net loss to cash provided by operating activities	'	'
Depreciation, depletion and amortization	13,206	15,056
Asset impairments (See Note 6)	237	'
Amortization of debt issuance costs	199	1,228
Accretion expense	451	409
Equity earnings in affiliate	-147	-224
(Gain)/Loss from disposition of property and equipment	-23	8
Bad debt expense	80	44
Mark-to-market on derivatives:	'	'
Total (gains) losses	1,134	-371
Cash settlements	4,184	8,006
Unit-based compensation programs	1,216	828
Discontinued operations	'	2,686
Changes in Assets and Liabilities:	'	'
Decrease in accounts receivable	-359	-1,212
(Increase) decrease in prepaid expenses	869	-110
(Increase) decrease in other assets	3	-1,107
Increase (decrease) in accounts payable	63	-434
Decrease in accrued liabilities	-4,666	-1,614
Decrease in royalty payable	-70	-54
Increase (decrease) in other liabilities	-1,398	1,114
Net cash provided by continuing operations	12,684	8,776
Net cash provided by discontinued operations	'	1,062
Net cash provided by operating activities	12,684	9,838
Cash flows from investing activities:	'	'
Cash paid for acquisitions, net of cash acquired	-1,351	-20,221
Development of oil and natural gas properties	-5,025	-12,564
Proceeds from sale of assets	58	58,987
Distributions from equity affiliate	180	135
Net cash provided by (used in) continuing operations	-6,138	26,337
Net cash used in discontinued operations	'	'
Net cash provided by (used in) investing activities	-6,138	26,337
Cash flows from financing activities:	'	'
Proceeds from issuance of debt	5,750	16,894
Repayment of debt	-4,500	-50,194
Repurchase of Class A, Class C and Class D interests	-2,468	'
Units tendered by employees for tax withholdings	-415	-185
Debt issue costs	-136	-925
Net cash used in continuing operations	-1,769	-34,410
Net cash used in discontinued operations	'	'
Net cash used in financing activities	-1,769	-34,410
Net increase in cash and cash equivalents	4,777	1,765
Cash and cash equivalents, beginning of period	4,894	1,959
Cash and cash equivalents, end of period	9,671	3,724
Supplemental disclosures of cash flow information:	'	'
Change in accrued capital expenditures	-219	333
Cash paid during the period for interest	($1,379)	($1,405)

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements Of Changes In Members' Equity (USD $)	Common Class A [Member]	Common Class B [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Total
In Thousands, except Share data
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	'	'
Distributions	'	'	'	'
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)	'	433,700	'	'
Unit-based compensation programs	'	1,216	'	1,216
Cancellation of units (in shares) (See Note 9)	-1,130,512	'	'	'
Cancellation of units (See Note 9)	-851	-1,617	'	-2,468
Net income (loss)	-46	-2,249	'	-2,295
Ending Balance at Sep. 30, 2014	1,694	93,249	'	94,943
Ending Balance (in shares) at Sep. 30, 2014	484,505	28,735,703	'	'
Beginning Balance at Jun. 30, 2014	'	'	'	'
Net income (loss)	113	5,542	'	5,655
Ending Balance at Sep. 30, 2014	$1,694	$93,249	'	$94,943
Ending Balance (in shares) at Sep. 30, 2014	484,505	28,735,703	'	'

Organization_And_Basis_Of_Pres

Organization And Basis Of Presentation	9 Months Ended
	Sep. 30, 2014
Organization And Basis Of Presentation [Abstract]	'
Organization And Basis Of Presentation	'
	1. ORGANIZATION AND BASIS OF PRESENTATION
	Organization
	Sanchez Production Partners LLC (SPP, we, us, our or the Company) (formerly Constellation Energy Partners LLC) was organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware. We completed our initial public offering on November 20, 2006, and currently trade on the NYSE MKT LLC (NYSE MKT) under the symbol “SPP”.  We are currently focused on the acquisition, development and production of oil and natural gas properties and other integrated assets.  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 and in Texas and Louisiana.
	Through subsidiaries, Sanchez Oil & Gas Corporation (SOG) owns a portion of our outstanding units.  As of September 30, 2014, Sanchez Energy Partners I, LP (SEP I), a subsidiary of SOG, owned 484,505, or 100%, of our Class A units and 5,139,345, or 17.9%, of our Class B common units.
	On October 3, 2014, Constellation Energy Partners LLC (CEP) changed its name to Sanchez Production Partners LLC.  The name change was effected pursuant to Section 18-202 of the Delaware Limited Liability Company Act (the DLLCA) by filing a Fourth Certificate of Amendment to Certificate of Formation with the Secretary of State of the State of Delaware.  Under the DLLCA and the Company’s Second Amended and Restated Operating Agreement, as amended, the name change did not require approval of the Company’s unitholders.
	On June 26, 2014, we settled the lawsuit brought by Constellation Energy Partners Holdings, LLC (CEPH), a subsidiary of Exelon Corporation, against us in the Court of Chancery of the State of Delaware (the Exelon Litigation).  In conjunction with the settlement, we paid CEPH $1.65 million in exchange for all of the Class C management incentive interests and Class D interests held by CEPH, which were all of such interests issued by SPP.  Effective with the acquisition of these interests from CEPH, we cancelled the Class C management incentive interests and Class D interests.
	On May 8, 2014, the Company and SP Holdings, LLC (the Manager), an affiliate of SOG, entered into a Shared Services Agreement (the Services Agreement) pursuant to which, as of July 1, 2014, the Manager provides services that the Company requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services.
	Basis of Presentation
	These unaudited condensed consolidated financial statements include the accounts of SPP and our wholly-owned subsidiaries.  All significant 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 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.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP.
	These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of SPP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2013, which was filed with the SEC on March 27, 2014.
	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 (NGL); 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.
	Discontinued Operations
	In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin in Alabama.  The related results of operations and cash flows have been classified as discontinued operations in the condensed consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information for the nine months ended September 30, 2013.  Unless otherwise indicated, information presented in the Notes to Condensed Consolidated Financial Statements relates only to the Company’s continuing operations.  Information related to discontinued operations is included in Note 3. Acquisitions and Divestiture.
	New Accounting Pronouncements
	From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the 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 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  This guidance changes the definition of a discontinued operation to include only those disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results.  This guidance is effective prospectively for fiscal years beginning after December 15, 2014.  The effects of this accounting standard on our financial position, results of operations and cash flows are not yet known.
	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, 2016.  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.
	In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  This guidance creates a new subtopic ASC 205-40, “Presentation of Financial Statements – Going Concern,” and provides guidance about management’s responsibility to evaluate whether there is a substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures.  The requirements in this guidance are effective for the annual period ending after December 15, 2016, which is fiscal 2017 for us, and for annual and interim periods thereafter.  Early application is permitted.  We acknowledge this new guidance and will comply with the disclosure requirements, if applicable, beginning in fiscal 2017.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2014
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, 2013.
	Earnings per Unit
	Basic earnings per unit (EPU) is computed 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 allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any.  The remaining net income (loss) is allocated to each class with the Class A units receiving 2% and the Class B units receiving 98%.
	As of September 30, 2014 and 2013, we had unvested restricted common units outstanding, which were considered dilutive securities.  These units will be considered in the diluted weighted average common units outstanding number in periods of net income.  In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number as they are not participating securities.
	The following table presents our calculation of basic and diluted units outstanding for the periods indicated:
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
	Weighted average units outstanding during period:
	Class A units - Basic		484,505		1,135,725		857,201		703,883
	Class B units - Basic		28,552,568		26,071,909		28,358,591		24,238,279
			29,037,073		27,207,634		29,215,792		24,942,162
	Weighted average units outstanding during period:
	Class A units - Diluted		484,505		1,135,725		857,201		703,883
	Class B units - Diluted		28,660,878		26,071,909		28,358,591		24,238,279
			29,145,383		27,207,634		29,215,792		24,942,162
	At September 30, 2014, we had 108,310 Class B common units that were restricted unvested common units granted and outstanding.  These units were included in the diluted weighted average common unit outstanding number for the three months ended September 30, 2014, but were excluded from the nine months ended September 30, 2014.
	The following table presents our basic and diluted income per unit for the three months ended September 30, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Income from continuing operations	$	5,655
	Distributions		-	$	-	$	-
	Assumed net income to be allocated	$	5,655	$	113	$	5,542
	Basic and diluted earnings per unit			$	0.23	$	0.19
	The following table presents our basic and diluted loss per unit for the three months ended September 30, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-3,257
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-3,257		-65		-3,192
	Discontinued operations		-		-		-
	Assumed net loss to be allocated	$	-3,257	$	-65	$	-3,192
	Basic and diluted loss from continuing operations per unit			$	-0.06	$	-0.12
	Basic and diluted loss from discontinued operations per unit			$	-	$	-
	Basic and diluted loss per unit			$	-0.06	$	-0.12
	The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-2,295
	Distributions		-	$	-	$	-
	Assumed net loss to be allocated	$	-2,295	$	-46	$	-2,249
	Basic and diluted loss per unit			$	-0.05	$	-0.08
	The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-12,791
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-12,791		-256		-12,535
	Discontinued operations		-2,686		-54		-2,632
	Assumed net loss to be allocated	$	-15,477	$	-310	$	-15,167
	Basic and diluted loss from continuing operations per unit			$	-0.36	$	-0.52
	Basic and diluted loss from discontinued operations per unit			$	-0.08	$	-0.11
	Basic and diluted loss per unit			$	-0.44	$	-0.63
	Cash
	All highly liquid investments with original maturities of three months or less are considered cash.  Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on.  There were no checks-in-transit reported in accounts payable at September 30, 2014 and December 31, 2013.
	Restricted  Cash
	Restricted cash, at September 30, 2014 and December 31, 2013, of $1.7 million was being held in escrow.  Of this balance, $0.6 million is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved.  The remaining amount of $1.1 million is related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama.  These funds will remain in escrow for a period ending February 28, 2015, pending certain post-closing conditions.  The restricted cash was classified as a non-current asset at December 31, 2013, but was reclassified to a current asset at September 30, 2014, based on the conditions of the cash held in the account.
	Accounts Receivable, Net
	Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments.  Oil receivables are generally collected within 30 days after the end of the month.  Natural gas receivables are generally collected within 60 days after the end of the month.  We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered.  Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted.  At September 30, 2014 and December 31, 2013, we had an allowance for doubtful accounts receivable of $0.2 million and $0.1 million, respectively.

Acquisitions_And_Divestiture

Acquisitions And Divestiture	9 Months Ended
	Sep. 30, 2014
Acquisitions And Divestiture [Abstract]	'
Acquisitions And Divestiture	'
	3. ACQUISITIONS AND DIVESTITURE
	Sale of Robinson’s Bend Field Assets
	On February 28, 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments that amounted to approximately $4.0 million.  We recorded a loss on the sale of approximately $3.1 million in the nine months ended September 30, 2013.  The sale of the Robinson’s Bend Field assets was initiated to provide the financial flexibility necessary to support our efforts for pursuing opportunities and further developing our properties in the Mid-Continent region, as well as reducing our outstanding debt.
	The following amounts relating to the Robinson’s Bend Field assets have been reported as discontinued operations in the condensed consolidated statements of operations for the three and nine months ended September 30, 2013 (in thousands):
		Three Months Ended			Nine Months Ended
		30-Sep-13			30-Sep-13
	Revenues	$	-		$	2,304
	Loss from discontinued operations	$	-		$	-2,686
	See Note 2 for information regarding earnings per unit, including earnings per unit data relating to loss from discontinued operations.
	The condensed consolidated statements of cash flows reflect discontinued operations for the nine months ended September 30, 2013.
	Acquisition of Oil, Natural Gas and Natural Gas Liquids Properties from SEP I
	On August 9, 2013, we acquired oil, natural gas and NGL assets in Texas and Louisiana from SEP I for a purchase price of $30.4 million.  In conjunction with the acquisition, SEP I received $20.1 million in cash; 1,130,512 Class A units, which represented 70.0% of the total Class A units outstanding as of such date, and 4,724,407 Class B units, which represented 16.6% of the total Class B units outstanding as of such date.  The cash portion of the transaction was financed with cash on hand and a borrowing of $16.7 million under our reserve-based credit facility.
	The acquired assets included 67 producing wells in Texas and Louisiana.  The primary factors considered by management in acquiring the SEP I properties included the belief that these wells provide an opportunity to significantly increase our reserves, production volumes and drilling portfolio, while maintaining our focus of increasing our oil-weighted assets.  The SEP I properties also provide us with access to exploitation and development potential.
	The following table summarizes the estimated values of assets acquired and liabilities assumed effective August 1, 2013 (in thousands):
			1-Aug-13
	Oil and natural gas properties, equipment and facilities		$	31,497
	Asset retirement obligation			-1,088
	Net assets acquired		$	30,409
	We accounted for our acquisition of oil and natural gas properties using the purchase method of accounting for business combinations, and therefore we estimated the fair value of the assets acquired and the liabilities assumed as of the acquisition date.  The fair value measurements of assets acquired and liabilities assumed were based on inputs that were not observable in the market and therefore represent Level 3 inputs.  The fair value 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 cost of capital rate.  These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.
	Pro Forma Information
	The following supplemental pro forma information presents consolidated results of operations as if the acquisition of the SEP I properties had occurred on January 1, 2013.  The supplemental unaudited pro forma information was derived from a) our historical consolidated statements of operations and b) the statements of operations of SEP I.  This information does not purport to be indicative of results of operations that would have occurred had the acquisition occurred on January 1, 2013, nor is such information indicative of any expected future results of operations.
		Pro Forma			Pro Forma
		Three Months Ended			Nine Months Ended
	(In thousands, except per unit data)	30-Sep-13			30-Sep-13
	Revenue	$	16,067		$	45,383
	Loss from continuing operations	$	-998		$	-5,448
	Discontinued operations	$	-		$	-2,686
	Net loss	$	-998		$	-8,134
	Loss from continuing operations per unit
	Class A units - Basic and diluted	$	-0.01		$	-0.07
	Class B units - Basic and diluted	$	-0.03		$	-0.19
	Discontinued operations per unit
	Class A units - Basic and diluted	$	-		$	-0.03
	Class B units - Basic and diluted	$	-		$	-0.09
	Net loss per unit
	Class A units - Basic and diluted	$	-0.01		$	-0.1
	Class B units - Basic and diluted	$	-0.03		$	-0.28
	Weighted average units outstanding
	Class A units - Basic and diluted		1,614,964			1,614,918
	Class B units - Basic and diluted		28,074,647			28,045,494
	Acquisition of Oil and Natural Gas Properties
	On April 9, 2014, we acquired a 20% working interest in nine producing wells and other assets for $1.4 million.  These assets are located in LaSalle Parish, Louisiana and are operated by SOG.  This purchase became effective May 1, 2014.  The impact of the acquisition of these properties was not material to our consolidated financial statements, so no pro forma information for this acquisition is provided.

Fair_Value_Messurements

Fair Value Messurements	9 Months Ended
	Sep. 30, 2014
Fair Value Measurements [Abstract]	'
Fair Value Measurements	'
	4. FAIR VALUE MEASUREMENTS
	We measure certain financial assets and liabilities at fair value.  Fair value is defined as an “exit price” which represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date.  As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in valuing an asset or liability.  The accounting guidance also requires the use of valuation techniques to measure fair value that maximize the use of observable inputs and minimize the use of unobservable inputs.  As a basis for considering such assumptions and inputs, a fair value hierarchy has been established which identifies and prioritizes three levels of inputs to be used in measuring fair value.
	The three levels of the fair value hierarchy are as follows:
	Level 1 – Observable inputs such as quoted prices (unadjusted) in active markets for identical assets or liabilities.
	Level 2 – Inputs other than the quoted prices in active markets that are observable either directly or indirectly, including: quoted prices for similar assets and liabilities in active markets; quoted prices for identical or similar assets and liabilities in markets that are not active or other inputs that are observable or can be corroborated by observable market data.
	Level 3 – Unobservable inputs that are supported by little or no market data and require the reporting entity to develop its own assumptions.
	As required by accounting guidance for fair value measurements, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 (in thousands):
		Fair Value Measurements at September 30, 2014
		Quoted Prices in		Significant Other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		30-Sep-14
	Risk Management Assets	$	-	$	5,663	$	-	$	-134	$	5,529
	Risk Management Liabilities		-		-379		-		134		-245
	Total Net Assets and Liabilities	$	-	$	5,284	$	-	$	-	$	5,284
	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, 2013 (in thousands):
		Fair Value Measurements at December 31, 2013
		Quoted Prices in		Significant Other
		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-13
	Risk Management Assets	$	-	$	11,577	$	-	$	-975	$	10,602
	Risk Management Liabilities		-		-975		-		975		-
	Total Net Assets and Liabilities	$	-	$	10,602	$	-	$	-	$	10,602
	As of September 30, 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 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.
	Reserve-Based Credit Facility – We believe that the carrying value of long-term debt for our reserve-based credit facility 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 reserve-based credit facility is discussed further in Note 7.
	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 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	9 Months Ended
	Sep. 30, 2014
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 as realized and unrealized gains (losses) on derivative instruments in the condensed consolidated statements of operations.
	As of September 30, 2014, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:
	MTM 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
	2014													1,610,000	$	5.75	1,610,000	$	5.75
	2015	1,215,420		$	4.25		1,153,487		$	4.25	1,096,023	$	4.26	1,050,219	$	4.26	4,515,149	$	4.25
	2016	1,010,633		$	4.21		967,290		$	4.21	923,541	$	4.21	893,568	$	4.21	3,795,032	$	4.21
																	9,920,181
	MTM Fixed Price Basis Swaps– Enable Gas Transmission, LLC (East), ONEOK Gas Transportation (Oklahoma) or Southern Star Central Gas Pipeline (Texas, Oklahoma, and Kansas)
		For the quarter ended (in MMBtu)
		March 31,					June 30,				September 30,			December 31,			Total
				Weighted					Weighted			Weighted			Weighted			Weighted
		Volume		Average $			Volume		Average $		Volume	Average $		Volume	Average $		Volume	Average $
	2014													1,047,963	$	0.39	1,047,963	$	0.39
																	1,047,963
	MTM 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
	2014													73,005	$	95.78	73,005	$	95.78
	2015	69,479		$	90.99		66,183		$	91.02	63,025	$	91.05	60,143	$	91.09	258,830	$	91.04
	2016	57,420		$	85.64		54,879		$	85.64	52,474	$	85.64	50,197	$	85.64	214,970	$	85.64
																	546,805
	The table below outlines the classification of our derivative financial instruments on the condensed consolidated balance sheet (in thousands):
					Fair Value of Asset/(Liability)
			Location of Asset/(Liability)		on Balance Sheet
	Derivative Type		on Balance Sheet		30-Sep-14			31-Dec-13
	Commodity – MTM		Risk management assets - current		$	4,617		$	10,043
	Commodity – MTM		Risk management assets  - non-current			1,046			1,534
			Total gross assets			5,663			11,577
	Commodity – MTM		Risk management liabilities – current			-334			-902
	Commodity – MTM		Risk management liabilities – non-current			-45			-73
			Total gross liabilities			-379			-975
			Total net assets and liabilities		$	5,284		$	10,602
	The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands):
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Three Months Ended September 30,
	Derivative Type		in Income		2014			2013
	Commodity – Mark-to-Market		Oil and natural gas sales		$	7,671		$	-406
	Interest Rate – Mark-to-Market		Interest expense			-			-
			Total		$	7,671		$	-406
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Nine Months Ended September 30,
	Derivative Type		in Income		2014			2013
	Commodity – Mark-to-Market		Oil and natural gas sales		$	-1,134		$	436
	Interest Rate – Mark-to-Market		Interest expense			-			-65
			Total		$	-1,134		$	371
	Derivative instruments expose us to counterparty credit risk.  Our commodity derivative instruments are currently with two 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 monitor the creditworthiness of our counterparties; however, we are not able to predict sudden changes in counterparties’ creditworthiness.  In addition, if such changes are sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk.  Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement.  Should one of our counterparties not perform, we may not realize the benefit of some of our derivative instruments with lower commodity prices and may incur losses.  We include a measure of counterparty credit risk in our estimates of the fair values of the derivative instruments in an asset position.
	We currently use our reserve-based credit facility to provide credit support for our derivative transactions.  As a result, we do not post cash collateral with our counterparties, and have minimal non-performance credit risk on our liabilities with our counterparties.  We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our net assets from counterparties.  At September 30, 2014 and December 31, 2013, the impact of non-performance credit risk on the valuation of our net assets from counterparties was not significant, and the entire amount was reflected as a decrease to our non-cash mark-to-market gain, respectively.
	Hedge Liquidation and Repositioning
	In the first quarter of 2013, we liquidated or repositioned certain of our hedges.  In connection with the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama, we liquidated 395,218 MMbtu of NYMEX swaps in 2013 and 1,634,530 MMbtu of NYMEX swaps in 2014 at a cost of $0.3 million.  In addition, we reduced our outstanding NYMEX swap positions in 2013 by 1,041,814 MMbtu by executing offsetting trades with one of our counterparties at a fixed price of $3.66 per Mcf.  These transactions ensured that our outstanding derivative positions in future periods are lower than our expected future natural gas production in those periods. We also amended a 2014 to 2015 oil trade with one of our hedge counterparties to lower the stated swap price from $98.10 to $93.50 per barrel, on a total of 58,157 barrels of oil.  We received proceeds of approximately $0.2 million upon execution of the amendment.  The proceeds were used for working capital purposes.
	In March 2013, we reduced our outstanding interest rate swaps that fix our LIBOR rate through 2014 to $30 million, which increased our interest rate swap settlements by $2.1 million.  This position was terminated in May 2013 resulting in an offsetting non-cash gain in our mark-to-market interest swap activities.

Oil_And_Natural_Gas_Properties

Oil And Natural Gas Properties	9 Months Ended
	Sep. 30, 2014
Oil And Natural Gas Properties [Abstract]	'
Oil And Natural Gas Properties	'
	6. OIL AND NATURAL GAS PROPERTIES
	Oil and natural gas properties consisted of the following (in thousands):
		September 30, 2014		December 31, 2013
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	642,923	$	636,816
	Unproved property		1,548		1,589
	Total property costs		644,471		638,405
	Materials and supplies		1,056		1,054
	Land		751		751
	Total		646,278		640,210
	Less: Accumulated depreciation, depletion, amortization and impairments		-508,208		-495,215
	Oil and natural gas properties and equipment, net	$	138,070	$	144,995
	Depreciation, depletion, amortization and impairments consisted of the following (in thousands):
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
	DD&A of oil and natural gas-related assets	$	4,836	$	5,491	$	13,206	$	15,056
	Asset impairments		43		-		237		-
	Total	$	4,879	$	5,491	$	13,443	$	15,056
	Impairment of Oil and Natural Gas Properties and Other Non-Current Assets
	For the nine months ended September 30, 2014, our non-cash impairment charges were $0.2 million to impair the value of our oil and natural gas fields in Texas and Louisiana, with an immaterial amount being recorded during the three months ended September 30, 2014.  For the three and nine months ended September  30, 2013, we did not have an impairment to record.  The impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report.
	Asset Sales
	During each of the three and nine months ended September 30, 2014 and September 30, 2013, we sold miscellaneous surplus equipment for less than $0.1 million resulting in an immaterial gain on the asset sales.
	Useful Lives
	Our furniture, fixtures and equipment are depreciated over a life of one to seven years, buildings are depreciated over a life of 20 years and pipeline and gathering systems are depreciated over a life of 25 to 40 years.
	Exploration and Dry Hole Costs
	We recorded no exploration and dry hole costs for the three and nine months ended September 30, 2014 and 2013, respectively.  These 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.

Debt

Debt	9 Months Ended
	Sep. 30, 2014
Debt [Abstract]	'
Debt	'
	7. DEBT
	Reserve-Based Credit Facility
	In May 2013, we refinanced our $350.0 million reserve-based credit facility with Societe Generale as administrative and collateral agent and a syndicate of lenders, extending its maturity to May 30, 2017 and increasing our borrowing base from $37.5 million to $55.0 million.  On May 6, 2014, our borrowing base under the reserve-based credit facility was increased to $70.0 million.  Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own, as well as various security and pledge agreements among us and certain of our subsidiaries and the administrative agent.  The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties.  As of September 30, 2014, we had borrowed $52.0 million under our reserve-based credit facility and our borrowing base was $70.0 million.  At September 30, 2014, the lenders and their percentage commitments in the reserve-based credit facility were Societe Generale (36.36%), OneWest Bank, FSB (36.36%) and BOKF NA, dba Bank of Oklahoma (27.28%).
	Borrowings under the reserve-based credit facility are available for acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes.  The reserve-based credit facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit.  As of September 30, 2014, no letters of credit were outstanding.
	At our election, interest for borrowings is determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (ABR) plus an applicable margin between 1.50% and 2.50% per annum based on utilization, plus (iii) a commitment fee of 0.50% 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 is generally payable at the applicable maturity date.
	The reserve-based credit facility contains various covenants that limit, among other things, our ability and certain of our subsidiaries’ ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets and make certain loans, acquisitions, capital expenditures and investments. The reserve-based credit facility limits our ability to pay distributions to unitholders and permits us to hedge our projected monthly production, as discussed below, and the interest rate on our borrowings.
	In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents and cash reserves of the Company)) to Adjusted EBITDA (generally, for any period, the sum of consolidated net income for such period plus (minus) the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives and other similar charges) of not more than 3.5 to 1.0;  (ii) Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and (iii) consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt (to the extent such payments are not past due), of not less than 1.0 to 1.0, all calculated pursuant to the requirements under Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging; ASC Topic 410, Asset Retirement and Environmental Obligations and ASC Topic 360, Property, Plant and Equipment.  All financial covenants are calculated using our consolidated financial information and are discussed below.
	The reserve-based credit facility also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, guaranties not being valid under the reserve-based credit facility and a change of control.  A change of control is generally defined as the occurrence of both of the following events: (i) wholly-owned subsidiaries of Constellation Energy Group, Inc. are the owner of 20% or less of an interest in us (which has now occurred) and (ii) any person or group of persons acting in concert are the owner of more than 35% of an interest in us.  These events have not both occurred, so a change in control had not occurred as of September 30, 2014.  If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise other rights and remedies.  The reserve-based credit facility contains a condition to borrowing and a representation that no material adverse effect (MAE) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole.  If a MAE were to occur, we would be prohibited from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable.
	The reserve-based credit facility limits our ability to pay distributions to unitholders.  We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the reserve-based credit facility exceed 90% of our borrowing base, after giving effect to the proposed distribution.  Our available cash is reduced by any cash reserves established by our board of managers for the proper conduct of our business.  As of September 30, 2014, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions.
	The reserve-based credit facility permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve-month period, the volumes of production hedged in any month may not exceed our reasonable business judgment of the production for such month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then-current strip pricing (provided that such projection shall not be more than 115% of the proved developed producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for the period beyond twelve months, the volumes of production hedged in any month may not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers.  The reserve-based credit facility also permits us to hedge the interest rate on up to 90% of the then-outstanding principal amounts of our indebtedness for borrowed money.
	The reserve-based credit facility contains no covenants related to SOG’s ownership in us.
	Compliance with Debt Covenants
	At September 30, 2014, we were in compliance with the financial covenants contained in our reserve-based credit facility.  We monitor compliance on an on-going basis.
	If we are unable to remain in compliance with the financial covenants contained in our reserve-based credit facility or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of our reserve-based credit facility, such that our outstanding debt could become then due and payable.  We may request waivers of compliance from the violated covenants from the lenders, but there is no assurance that such waivers would be granted.
	The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties.  As of September 30, 2014, our borrowing base was $70.0 million.  The borrowing base is re-determined semi-annually, 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.
	Funds Available for Borrowing
	As of September 30, 2014 and December 31, 2013, we had $52.0 million and $50.7 million, respectively, in outstanding debt under our reserve-based credit facility. As of September 30, 2014, we had $18.0 million available under our reserve-based credit facility.
	Debt Issue Costs
	As of September 30, 2014, our unamortized debt issue costs were approximately $0.8 million. These costs are being amortized over the life of our reserve-based credit facility.  At December 31, 2013, our unamortized debt issue costs were approximately $0.8 million.

Asset_Retirement_Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2014
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 following table is a reconciliation of the ARO (in thousands):
		September 30,		December 31,
		2014		2013
	Asset retirement obligation, beginning balance	$	9,513	$	7,665
	Liabilities added from acquisitions		79		1,088
	Liabilities added from drilling		42		244
	Settlements		-		-3
	Accretion expense		451		519
	Asset retirement obligation, ending balance	$	10,085	$	9,513
	Additional asset retirement obligations 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 asset retirement obligations. At September 30, 2014  and December 31, 2013, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations.

Commitments_And_Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2014
Commitments And Contingencies [Abstract]	'
Commitments And Contingencies	'
	9. COMMITMENTS AND CONTINGENCIES
	On August 30, 2013, a lawsuit was filed in the Chancery Court of the State of Delaware by Constellation Energy Partners Management, LLC (CEPM), Gary M. Pittman and John R. Collins against the Company, certain of its officers and managers, SOG and SEP I (the PostRock Litigation) in connection with the Company’s closing on August 9, 2013 of the purchase of oil and natural gas properties from SEP I and the issuance of units in connection therewith.  The plaintiffs contended, among other things, that the issuance of the units to SEP I in connection with the acquisition was not permitted under the Company’s operating agreement, that Messrs. Pittman and Collins should not have been removed as the Class A managers of the Company’s board of managers, and that SEP I, SOG and our current Class A managers participated in bad faith conduct of the other defendants and interfered with CEPM’s contractual rights under the Company’s operating agreement. The plaintiffs alleged claims against the Company and certain of its managers and officers relating to breach of contract, breach of the duty of good faith, and breach of the implied covenant of good faith and fair dealing; the plaintiffs also alleged aiding and abetting and tortuous interference claims against SOG, SEP I and our current Class A managers.  The plaintiffs sought, among other things, declaratory relief reappointing Messrs. Pittman and Collins to the Company’s board of managers and removing our current Class A managers therefrom, and an injunction against the Company taking any further action outside the ordinary course of business during the pendency of the litigation, declaratory relief rescinding the units issued by the Company to SEP I, declaratory relief that CEPM had sole voting power with respect to the outstanding Class A units, declaratory relief that the Company’s officers and managers breached fiduciary and contractual duties and were not entitled to indemnification from the Company as a result thereof, and monetary damages.  On March 31, 2014, the parties to the lawsuit reached a settlement agreement and the lawsuit was subsequently dismissed.  As a result of the settlement, the Class A units acquired by SEP I in the August 2013 transaction were returned to SPP and cancelled in exchange for $0.8 million; CEPM transferred 100% of its Class A units and 414,938 of SPP’s Class B units to SEP I in exchange for an aggregate payment of $1.0 million from SEP I, and SPP paid $6.5 million to CEPM.  In addition, pursuant to the terms of the settlement, CEPM agreed to sell its remaining Class B units over the next nine months, with SEP I providing up to a $5.0 million backstop payment to CEPM to the extent proceeds received by CEPM from such sale do not meet or exceed a specified amount.  As a result of the settlement, the settling parties filed a stipulation in the Court of Chancery of the State of Delaware seeking to lift the preliminary injunction issued on December 3, 2013, and the litigation was dismissed with prejudice.  The settlement also included mutual releases between the plaintiffs and defendants.  In connection with the settlement, we received $1.25 million on April 10, 2014, under our directors and officers insurance policy.
	On February 28, 2014, a lawsuit was filed in the Chancery Court of the State of Delaware by CEPH against the Company (the Exelon Litigation) seeking repayment of suspended distributions in relation to the Class D Interests held by CEPH.  In 2006, Constellation Holding, Inc (CHI), which merged with and into CEPH in December 2012, purchased the Company’s Class D Interests for $8.0 million.  The $8.0 million was to be repaid to CEPH in quarterly distributions of $333,333.33 over a period of six years; however, these distributions could be temporarily suspended if a dispute arose over pricing formulas related to the sale of natural gas from the Robinson’s Bend properties.  A dispute arose, so the distributions were suspended pursuant to the Company’s operating agreement and never reinstated.  CEPH contended, among other things, that the Company breached its contract to pay the quarterly distributions, acted in bad faith and received unjust enrichment by suspending the quarterly distributions.  On June 26, 2014, the parties to the lawsuit reached a settlement agreement and the lawsuit was subsequently dismissed.  In conjunction with the settlement, we paid CEPH $1.65 million in exchange for all of the Class C management incentive interests and the Class D interests held by CEPH, which accounted for all such interests issued by SPP.  Effective with the acquisition from CEPH, we cancelled the Class C management incentive interests and Class D interests.

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2014
Related Party Transactions [Abstract]	'
Related Party Transations	'
	10. RELATED PARTY TRANSACTIONS
	Unit Ownership
	SOG, through a subsidiary, owns a portion of our outstanding units. As of September 30, 2014, SEP I, a subsidiary of SOG, owned 484,505, or 100%, of our Class A units and 5,139,345, or 17.9%, of our Class B common units.
	Sanchez-Related Announcements
	In August 2013, SEP I acquired certain of our Class A units and Class B common units and one Class Z unit in one transaction which represented a 19.2% ownership interest in us at September 30, 2014.  These units were issued to SEP I, along with cash, in exchange for oil and natural gas properties located in Texas and Louisiana.
	In August 2013, the Company also entered into a Registration Rights Agreement with SEP I pursuant to which the Company granted to SEP I certain registration rights related to the unit consideration thereunder.  Under the Registration Rights Agreement, the Company granted SEP I demand registration rights with respect to the preparation and filing with the SEC of one or more registration statements for the purpose of registering the resale of the securities that will be registered.
	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 the Company requires to operate its 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 the Company’s properties other than its assets located in the Mid-Continent region, (ii) a $1,000,000 administrative fee, with $500,000 paid on May 8, 2014 and $500,000 paid on July 1, 2014, the date that the Manager provided notice of its commitment to provide services under the Services Agreement (the In-Service Date), (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 equity by the Company.  In addition, upon the first acquisition of assets from an affiliate of the Manager, the Company is required to amend its operating agreement and issue a new class of incentive distribution right to the Manager.
	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.  The Services Agreement can be terminated early (i) by either party at any time after 24 months from the In-Service Date with six months’ notice to the other party, (ii) by either party if there is an uncured material breach thereunder by the other party or (iii) by the Company if there is a change in control of the Manager and the Company pays the termination payment discussed below.  If there is a termination of the Services Agreement other than by either party at the end of the agreement’s term or by the Company for a breach by the Manager, then the Company will owe a termination payment to the Manager equal to $5,000,000, plus 5% of the transaction value of all asset acquisitions theretofore consummated; if the Company terminates after the 24-month anniversary of the In-Service Date upon six months’ notice, the Company will also owe to the Manager all costs and expenses of the Manager that result from such termination.  Through September 30, 2014, the Company has paid $0.8 million to SOG under the Services Agreement.
	On May 8, 2014, the Company and SOG entered into a Contract Operating Agreement (the Operating Agreement) pursuant to which SOG has agreed either to provide services to operate, develop and produce the Company’s oil and natural gas properties or to engage a third-party operator to do so, other than with respect to the Company’s properties in the Mid-Continent region.  In connection with providing services under the Operating Agreement, SOG will be reimbursed for all direct charges under COPAS.
	On May 8, 2014, the Company, the Manager and SOG entered into a Transition Agreement (the Transition Agreement) pursuant to which the Company agreed to make available to the Manager and SOG certain of the Company’s employees for SOG or the Manager to provide services under the Services Agreement and Operating agreement.  No compensation was paid by any party for the provision or use of employees under the Transition Agreement.  All employees remained under the day-to-day control of the Company, and the Company retained the right to terminate employees and had no obligation to hire new employees.  SOG had the right to hire any Company employees and thereafter, SOG is responsible for all costs and expenses for such employees.  As of the In-Service Date, all employees of the Company located in the Houston office became employees of SOG, except for the Chief Executive Officer and the Chief Financial Officer, who remain employees of the Company.
	On May 8, 2014, the Company, SOG and certain subsidiaries of the Company entered into a Geophysical Seismic Data Use License Agreement (the License Agreement) pursuant to which SOG provides to the Company a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to the Company’s oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors.
	Class Z Unit
	SEP I holds the one Class Z unit of SPP.  This one unit is a non-voting unit, except for voting as a separate class to approve the issuance of additional Company securities, other than Class B common units, prior to the issuance of such securities.  The Class Z unit is a non-economic interest, without any right to participate in distributions or allocations.

UnitBased_Compensation

Unit-Based Compensation	9 Months Ended
	Sep. 30, 2014
Unit-Based Compensation [Abstract]	'
Unit-Based Compensation	'
	11. UNIT-BASED COMPENSATION
	We have the following unit-based compensation plans:
	We have the 2009 Omnibus Incentive Compensation Plan (Omnibus Plan), which is a plan under which restricted common unit awards are granted to certain employees in Texas.  The Omnibus Plan provides 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.  Awards under the Omnibus Plan may be paid in cash, units or any combination thereof as determined by the compensation committee of our board of managers.
	Restricted unit activity (number of units) under the Omnibus Plan was as follows:
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2013	336,551	$	3.29
	Vested	-171,692		3.33
	Granted	-		-
	Returned/Cancelled	-57,214		3.33
	Outstanding at March 31, 2014	107,645	$	3.2
	Vested	-37,653		2.44
	Granted	346,403		2.44
	Returned/Cancelled	-15,981		3.44
	Outstanding at June 30, 2014	400,414	$	2.39
	Vested	-236,809		2.46
	Granted	-		-
	Returned/Cancelled	-77,187		2.44
	Outstanding at September 30, 2014	86,418	$	3.15
	We have the Long-Term Incentive Plan (L-TIP), which is a plan under which restricted common unit awards are granted to certain field employees in Kansas and Oklahoma and to certain employees in Texas.
	Restricted unit activity (number of units) under the L-TIP Plan was as follows:
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2013	43,776	$	2.87
	Vested	-16,415		2.87
	Granted	-		-
	Returned/Cancelled	-5,469		2.87
	Outstanding at March 31, 2014	21,892	$	2.87
	Vested	-22,028		2.44
	Granted	103,278		2.44
	Returned/Cancelled	-		-
	Outstanding at June 30, 2014	103,142	$	2.53
	Vested	-60,938		2.44
	Granted	-		-
	Returned/Cancelled	-20,312		2.44
	Outstanding at September 30, 2014	21,892	$	2.87
	We recognized approximately $1.2 million and $0.8 million on non-cash compensation expense related to our unit-based compensation plans in the nine months ended September 30, 2014 and September 30, 2013, respectively.

Distributions_To_Unitholders

Distributions To Unitholders	9 Months Ended
	Sep. 30, 2014
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 of managers for the proper conduct of our business) from which to pay distributions.

Members_Equity

Members' Equity	9 Months Ended
	Sep. 30, 2014
Members' Equity [Abstract]	'
Members' Equity	'
	13. MEMBERS’ EQUITY
	2014  Equity
	At September 30, 2014, we had 484,505 Class A units and 28,735,703 Class B common units outstanding, which included 21,892 unvested restricted common units issued under our L-TIP Plan and 86,418 unvested restricted common units issued under our Omnibus Plan.
	At  September 30, 2014, we had granted 424,231 common units of the 450,000 common units available under our L-TIP Plan. Of these grants, 402,339 have vested.
	At September 30, 2014,  we had granted 1,562,687 common units of the 1,650,000 common units available under our Omnibus Plan. Of these grants, 1,476,269 have vested.
	For the nine months ended September 30, 2014, 160,182 common units were tendered by our employees for tax withholding purposes.  These units, costing approximately $0.4 million, were returned to their respective plan and are available for future grants.
	2013 Equity
	At December 31, 2013, we had 1,615,017 Class A units and 28,462,185 Class B common units outstanding, which included 43,776 unvested restricted common units issued under our L-TIP Plan and 336,551 unvested restricted common units issued under our Omnibus Plan.
	At December 31, 2013, we had granted 346,734 common units of the 450,000 common units available under our L-TIP Plan. Of these grants, 302,958 have vested.
	At December 31, 2013, we had granted 1,366,666 common units of the 1,650,000 common units available under our Omnibus Plan. Of these grants, 1,030,115 have vested.
	For the twelve months ended December 31, 2013, 139,810 common units were tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million,  were returned to their respective plan and are available for future grants.

Subsequent_Events

Subsequent Events	9 Months Ended
	Sep. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Events	'
	14. SUBSEQUENT EVENTS
	The following event occurred subsequent to the date of the balance sheet and prior to the filing of this Quarterly Report on Form 10-Q that could have a material impact on our consolidated financial statements or results of operations:
	On October 31, 2014, we reached an agreement with our lenders to forego the required semi-annual redetermination process for our reserve-based credit facility until the end of the current year.

Organization_And_Basis_Of_Pres1

Organization And Basis Of Presentation (Policies)	9 Months Ended
	Sep. 30, 2014
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 significant 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 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.  The year-end balance sheet data was derived from audited financial statements, but does not include all disclosures required by U.S. GAAP.
	These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of SPP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2013, which was filed with the SEC on March 27, 2014.
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 (NGL); 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.
Discontinued Operations	'
	Discontinued Operations
	In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin in Alabama.  The related results of operations and cash flows have been classified as discontinued operations in the condensed consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information for the nine months ended September 30, 2013.  Unless otherwise indicated, information presented in the Notes to Condensed Consolidated Financial Statements relates only to the Company’s continuing operations.  Information related to discontinued operations is included in Note 3. Acquisitions and Divestiture.
New Accounting Pronouncements	'
	New Accounting Pronouncements
	From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the 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 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  This guidance changes the definition of a discontinued operation to include only those disposals of components of an entity that represent a strategic shift that has or will have a major effect on an entity’s operations and financial results.  This guidance is effective prospectively for fiscal years beginning after December 15, 2014.  The effects of this accounting standard on our financial position, results of operations and cash flows are not yet known.
	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, 2016.  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.
	In August 2014, the FASB issued ASU No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  This guidance creates a new subtopic ASC 205-40, “Presentation of Financial Statements – Going Concern,” and provides guidance about management’s responsibility to evaluate whether there is a substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures.  The requirements in this guidance are effective for the annual period ending after December 15, 2016, which is fiscal 2017 for us, and for annual and interim periods thereafter.  Early application is permitted.  We acknowledge this new guidance and will comply with the disclosure requirements, if applicable, beginning in fiscal 2017.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2014
Summary Of Significant Accounting Policies [Abstract]	'
Earnings Per Unit	'
	Earnings per Unit
	Basic earnings per unit (EPU) is computed 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 allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any.  The remaining net income (loss) is allocated to each class with the Class A units receiving 2% and the Class B units receiving 98%.
	As of September 30, 2014 and 2013, we had unvested restricted common units outstanding, which were considered dilutive securities.  These units will be considered in the diluted weighted average common units outstanding number in periods of net income.  In periods of net losses, these units are excluded from the diluted weighted average common unit outstanding number as they are not participating securities.
	The following table presents our calculation of basic and diluted units outstanding for the periods indicated:
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
	Weighted average units outstanding during period:
	Class A units - Basic		484,505		1,135,725		857,201		703,883
	Class B units - Basic		28,552,568		26,071,909		28,358,591		24,238,279
			29,037,073		27,207,634		29,215,792		24,942,162
	Weighted average units outstanding during period:
	Class A units - Diluted		484,505		1,135,725		857,201		703,883
	Class B units - Diluted		28,660,878		26,071,909		28,358,591		24,238,279
			29,145,383		27,207,634		29,215,792		24,942,162
	At September 30, 2014, we had 108,310 Class B common units that were restricted unvested common units granted and outstanding.  These units were included in the diluted weighted average common unit outstanding number for the three months ended September 30, 2014, but were excluded from the nine months ended September 30, 2014.
	The following table presents our basic and diluted income per unit for the three months ended September 30, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Income from continuing operations	$	5,655
	Distributions		-	$	-	$	-
	Assumed net income to be allocated	$	5,655	$	113	$	5,542
	Basic and diluted earnings per unit			$	0.23	$	0.19
	The following table presents our basic and diluted loss per unit for the three months ended September 30, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-3,257
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-3,257		-65		-3,192
	Discontinued operations		-		-		-
	Assumed net loss to be allocated	$	-3,257	$	-65	$	-3,192
	Basic and diluted loss from continuing operations per unit			$	-0.06	$	-0.12
	Basic and diluted loss from discontinued operations per unit			$	-	$	-
	Basic and diluted loss per unit			$	-0.06	$	-0.12
	The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-2,295
	Distributions		-	$	-	$	-
	Assumed net loss to be allocated	$	-2,295	$	-46	$	-2,249
	Basic and diluted loss per unit			$	-0.05	$	-0.08
	The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-12,791
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-12,791		-256		-12,535
	Discontinued operations		-2,686		-54		-2,632
	Assumed net loss to be allocated	$	-15,477	$	-310	$	-15,167
	Basic and diluted loss from continuing operations per unit			$	-0.36	$	-0.52
	Basic and diluted loss from discontinued operations per unit			$	-0.08	$	-0.11
	Basic and diluted loss per unit			$	-0.44	$	-0.63
Cash	'
	Cash
	All highly liquid investments with original maturities of three months or less are considered cash.  Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on.  There were no checks-in-transit reported in accounts payable at September 30, 2014 and December 31, 2013.
Restricted Cash	'
	Restricted  Cash
	Restricted cash, at September 30, 2014 and December 31, 2013, of $1.7 million was being held in escrow.  Of this balance, $0.6 million is related to a vendor dispute, and will remain in the escrow account until the dispute has been resolved.  The remaining amount of $1.1 million is related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama.  These funds will remain in escrow for a period ending February 28, 2015, pending certain post-closing conditions.  The restricted cash was classified as a non-current asset at December 31, 2013, but was reclassified to a current asset at September 30, 2014, based on the conditions of the cash held in the account.
Accounts Receivable, Net	'
	Accounts Receivable, Net
	Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments.  Oil receivables are generally collected within 30 days after the end of the month.  Natural gas receivables are generally collected within 60 days after the end of the month.  We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered.  Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted.  At September 30, 2014 and December 31, 2013, we had an allowance for doubtful accounts receivable of $0.2 million and $0.1 million, respectively.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2014
Summary Of Significant Accounting Policies [Abstract]	'
Schedule Of Weighted Average Units Outstanding	'
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
	Weighted average units outstanding during period:
	Class A units - Basic		484,505		1,135,725		857,201		703,883
	Class B units - Basic		28,552,568		26,071,909		28,358,591		24,238,279
			29,037,073		27,207,634		29,215,792		24,942,162
	Weighted average units outstanding during period:
	Class A units - Diluted		484,505		1,135,725		857,201		703,883
	Class B units - Diluted		28,660,878		26,071,909		28,358,591		24,238,279
			29,145,383		27,207,634		29,215,792		24,942,162
Earnings Per Common Unit Amounts	'
	The following table presents our basic and diluted income per unit for the three months ended September 30, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Income from continuing operations	$	5,655
	Distributions		-	$	-	$	-
	Assumed net income to be allocated	$	5,655	$	113	$	5,542
	Basic and diluted earnings per unit			$	0.23	$	0.19
	The following table presents our basic and diluted loss per unit for the three months ended September 30, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-3,257
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-3,257		-65		-3,192
	Discontinued operations		-		-		-
	Assumed net loss to be allocated	$	-3,257	$	-65	$	-3,192
	Basic and diluted loss from continuing operations per unit			$	-0.06	$	-0.12
	Basic and diluted loss from discontinued operations per unit			$	-	$	-
	Basic and diluted loss per unit			$	-0.06	$	-0.12
	The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2014 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-2,295
	Distributions		-	$	-	$	-
	Assumed net loss to be allocated	$	-2,295	$	-46	$	-2,249
	Basic and diluted loss per unit			$	-0.05	$	-0.08
	The following table presents our basic and diluted loss per unit for the nine months ended September 30, 2013 (in thousands, except for per unit amounts):
		Total		Class A Units		Class B Units
	Loss from continuing operations	$	-12,791
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-12,791		-256		-12,535
	Discontinued operations		-2,686		-54		-2,632
	Assumed net loss to be allocated	$	-15,477	$	-310	$	-15,167
	Basic and diluted loss from continuing operations per unit			$	-0.36	$	-0.52
	Basic and diluted loss from discontinued operations per unit			$	-0.08	$	-0.11
	Basic and diluted loss per unit			$	-0.44	$	-0.63

Acquisitions_And_Divestiture_T

Acquisitions And Divestiture (Tables)	9 Months Ended
	Sep. 30, 2014
Acquisitions And Divestiture [Abstract]	'
Schedule Of Discontinued Operations	'
		Three Months Ended			Nine Months Ended
		30-Sep-13			30-Sep-13
	Revenues	$	-		$	2,304
	Loss from discontinued operations	$	-		$	-2,686
Estimated Values Of Assets Acquired And Liabilities Assumed	'
			1-Aug-13
	Oil and natural gas properties, equipment and facilities		$	31,497
	Asset retirement obligation			-1,088
	Net assets acquired		$	30,409
Supplemental Pro Forma Information	'
		Pro Forma			Pro Forma
		Three Months Ended			Nine Months Ended
	(In thousands, except per unit data)	30-Sep-13			30-Sep-13
	Revenue	$	16,067		$	45,383
	Loss from continuing operations	$	-998		$	-5,448
	Discontinued operations	$	-		$	-2,686
	Net loss	$	-998		$	-8,134
	Loss from continuing operations per unit
	Class A units - Basic and diluted	$	-0.01		$	-0.07
	Class B units - Basic and diluted	$	-0.03		$	-0.19
	Discontinued operations per unit
	Class A units - Basic and diluted	$	-		$	-0.03
	Class B units - Basic and diluted	$	-		$	-0.09
	Net loss per unit
	Class A units - Basic and diluted	$	-0.01		$	-0.1
	Class B units - Basic and diluted	$	-0.03		$	-0.28
	Weighted average units outstanding
	Class A units - Basic and diluted		1,614,964			1,614,918
	Class B units - Basic and diluted		28,074,647			28,045,494

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2014
Fair Value Measurements [Abstract]	'
Fair Value Of Assets And Liabilities On A Recurring Basis	'
	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2014 (in thousands):
		Fair Value Measurements at September 30, 2014
		Quoted Prices in		Significant Other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		30-Sep-14
	Risk Management Assets	$	-	$	5,663	$	-	$	-134	$	5,529
	Risk Management Liabilities		-		-379		-		134		-245
	Total Net Assets and Liabilities	$	-	$	5,284	$	-	$	-	$	5,284
	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, 2013 (in thousands):
		Fair Value Measurements at December 31, 2013
		Quoted Prices in		Significant Other
		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-13
	Risk Management Assets	$	-	$	11,577	$	-	$	-975	$	10,602
	Risk Management Liabilities		-		-975		-		975		-
	Total Net Assets and Liabilities	$	-	$	10,602	$	-	$	-	$	10,602

Derivative_And_Financial_Instr1

Derivative And Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2014
Derivative And Financial Instruments [Abstract]	'
Summary Of Hedges In Place	'
	MTM 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
	2014													1,610,000	$	5.75	1,610,000	$	5.75
	2015	1,215,420		$	4.25		1,153,487		$	4.25	1,096,023	$	4.26	1,050,219	$	4.26	4,515,149	$	4.25
	2016	1,010,633		$	4.21		967,290		$	4.21	923,541	$	4.21	893,568	$	4.21	3,795,032	$	4.21
																	9,920,181
	MTM Fixed Price Basis Swaps– Enable Gas Transmission, LLC (East), ONEOK Gas Transportation (Oklahoma) or Southern Star Central Gas Pipeline (Texas, Oklahoma, and Kansas)
		For the quarter ended (in MMBtu)
		March 31,					June 30,				September 30,			December 31,			Total
				Weighted					Weighted			Weighted			Weighted			Weighted
		Volume		Average $			Volume		Average $		Volume	Average $		Volume	Average $		Volume	Average $
	2014													1,047,963	$	0.39	1,047,963	$	0.39
																	1,047,963
	MTM 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
	2014													73,005	$	95.78	73,005	$	95.78
	2015	69,479		$	90.99		66,183		$	91.02	63,025	$	91.05	60,143	$	91.09	258,830	$	91.04
	2016	57,420		$	85.64		54,879		$	85.64	52,474	$	85.64	50,197	$	85.64	214,970	$	85.64
																	546,805
Fair Value for Risk Management Assets and Liabilities	'
					Fair Value of Asset/(Liability)
			Location of Asset/(Liability)		on Balance Sheet
	Derivative Type		on Balance Sheet		30-Sep-14			31-Dec-13
	Commodity – MTM		Risk management assets - current		$	4,617		$	10,043
	Commodity – MTM		Risk management assets  - non-current			1,046			1,534
			Total gross assets			5,663			11,577
	Commodity – MTM		Risk management liabilities – current			-334			-902
	Commodity – MTM		Risk management liabilities – non-current			-45			-73
			Total gross liabilities			-379			-975
			Total net assets and liabilities		$	5,284		$	10,602
Schedule Of Effect Of Derivative Instruments On Condensed Consolidated Statements Of Operations	'
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Three Months Ended September 30,
	Derivative Type		in Income		2014			2013
	Commodity – Mark-to-Market		Oil and natural gas sales		$	7,671		$	-406
	Interest Rate – Mark-to-Market		Interest expense			-			-
			Total		$	7,671		$	-406
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Nine Months Ended September 30,
	Derivative Type		in Income		2014			2013
	Commodity – Mark-to-Market		Oil and natural gas sales		$	-1,134		$	436
	Interest Rate – Mark-to-Market		Interest expense			-			-65
			Total		$	-1,134		$	371

Oil_And_Natural_Gas_Properties1

Oil And Natural Gas Properties (Tables)	9 Months Ended
	Sep. 30, 2014
Oil And Natural Gas Properties [Abstract]	'
Oil and Natural Gas Properties	'
		September 30, 2014		December 31, 2013
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	642,923	$	636,816
	Unproved property		1,548		1,589
	Total property costs		644,471		638,405
	Materials and supplies		1,056		1,054
	Land		751		751
	Total		646,278		640,210
	Less: Accumulated depreciation, depletion, amortization and impairments		-508,208		-495,215
	Oil and natural gas properties and equipment, net	$	138,070	$	144,995
Depletion, Depreciation, Amortization and Impairments	'
		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
	DD&A of oil and natural gas-related assets	$	4,836	$	5,491	$	13,206	$	15,056
	Asset impairments		43		-		237		-
	Total	$	4,879	$	5,491	$	13,443	$	15,056

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2014
Asset Retirement Obligation [Abstract]	'
Reconciliation of Asset Retirement Obligation	'
		September 30,		December 31,
		2014		2013
	Asset retirement obligation, beginning balance	$	9,513	$	7,665
	Liabilities added from acquisitions		79		1,088
	Liabilities added from drilling		42		244
	Settlements		-		-3
	Accretion expense		451		519
	Asset retirement obligation, ending balance	$	10,085	$	9,513

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2014
2009 Omnibus Incentive Compensation Plan [Member]	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Schedule Of Units Granted	'
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2013	336,551	$	3.29
	Vested	-171,692		3.33
	Granted	-		-
	Returned/Cancelled	-57,214		3.33
	Outstanding at March 31, 2014	107,645	$	3.2
	Vested	-37,653		2.44
	Granted	346,403		2.44
	Returned/Cancelled	-15,981		3.44
	Outstanding at June 30, 2014	400,414	$	2.39
	Vested	-236,809		2.46
	Granted	-		-
	Returned/Cancelled	-77,187		2.44
	Outstanding at September 30, 2014	86,418	$	3.15
Long Term Incentive Plan [Member]	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Schedule Of Units Granted	'
			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit
	Outstanding at December 31, 2013	43,776	$	2.87
	Vested	-16,415		2.87
	Granted	-		-
	Returned/Cancelled	-5,469		2.87
	Outstanding at March 31, 2014	21,892	$	2.87
	Vested	-22,028		2.44
	Granted	103,278		2.44
	Returned/Cancelled	-		-
	Outstanding at June 30, 2014	103,142	$	2.53
	Vested	-60,938		2.44
	Granted	-		-
	Returned/Cancelled	-20,312		2.44
	Outstanding at September 30, 2014	21,892	$	2.87

Recovered_Sheet1

Organization and Basis of Presentation (Details) (USD $)	9 Months Ended		0 Months Ended	9 Months Ended	0 Months Ended	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2014	Jun. 26, 2014	Aug. 09, 2013	Sep. 30, 2014	Aug. 09, 2013	Sep. 30, 2014
	segment		Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]
			Common Class A [Member]	Common Class A [Member]	Common Class B [Member]	Common Class B [Member]
Organization [Line Items]	'	'	'	'	'	'
Units owned by third party	'	'	1,130,512	484,505	4,724,407	5,139,345
Units owned by third party, percentage of total shares	'	'	70.00%	100.00%	16.60%	17.90%
Amount paid for repurchased shares	'	$1.65	'	'	'	'
Number of business segments	1	'	'	'	'	'

Recovered_Sheet2

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014
In Millions, except Share data, unless otherwise specified			Common Class A [Member]	Common Class B [Member]
Significant Accounting Policies [Line Items]	'	'	'	'
Net income (loss) alloxation	'	'	2.00%	98.00%
Restricted unvested common units granted and outstanding	'	'	'	108,310
Restricted cash held in escrow	$1.70	$1.70	'	'
Escrow account related to vendor dispute	0.6	'	'	'
Escrow account	1.1	'	'	'
Allowance for doubtful accounts	$0.20	$0.10	'	'

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Schedule Of Weighted Average Units Outstanding) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Class Of Stock [Line Items]	'	'	'	'
Weighted average units outstanding during period - Basic	29,037,073	27,207,634	29,215,792	24,942,162
Weighted average units outstanding during period	29,145,383	27,207,634	29,215,792	24,942,162
Common Class A [Member]	'	'	'	'
Class Of Stock [Line Items]	'	'	'	'
Weighted average units outstanding during period - Basic	484,505	1,135,725	857,201	703,883
Weighted average units outstanding during period	484,505	1,135,725	857,201	703,883
Common Class B [Member]	'	'	'	'
Class Of Stock [Line Items]	'	'	'	'
Weighted average units outstanding during period - Basic	28,552,568	26,071,909	28,358,591	24,238,279
Weighted average units outstanding during period	28,660,878	26,071,909	28,358,591	24,238,279

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Earnings Per Common Unit Amounts) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Class Of Stock [Line Items]	'	'	'	'
Income (loss) from continuing operations	$5,655	($3,257)	($2,295)	($12,791)
Income (loss) from continuing operations	5,655	-3,257	-2,295	-12,791
Discontinued operations	'	'	'	-2,686
Net income (loss)	5,655	-3,257	-2,295	-15,477
Common Class A [Member]	'	'	'	'
Class Of Stock [Line Items]	'	'	'	'
Income (loss) from continuing operations	'	-65	'	-256
Discontinued operations	'	'	'	-54
Net income (loss)	113	-65	-46	-310
Basic and diluted loss from continuing operations per unit	'	($0.06)	'	($0.36)
Basic and diluted loss from discontinued operations per unit	'	'	'	($0.08)
Basic and diluted earnings (loss) per unit	$0.23	($0.06)	($0.05)	($0.44)
Common Class B [Member]	'	'	'	'
Class Of Stock [Line Items]	'	'	'	'
Income (loss) from continuing operations	'	-3,192	'	-12,535
Discontinued operations	'	'	'	-2,632
Net income (loss)	$5,542	($3,192)	($2,249)	($15,167)
Basic and diluted loss from continuing operations per unit	'	($0.12)	'	($0.52)
Basic and diluted loss from discontinued operations per unit	'	'	'	($0.11)
Basic and diluted earnings (loss) per unit	$0.19	($0.12)	($0.08)	($0.63)

Acquisitions_And_Divestiture_N

Acquisitions And Divestiture (Narrative) (Details) (USD $)	0 Months Ended	9 Months Ended		0 Months Ended			9 Months Ended	0 Months Ended	9 Months Ended	0 Months Ended
In Millions, except Share data, unless otherwise specified	Feb. 28, 2013	Sep. 30, 2013	Aug. 09, 2013	Aug. 09, 2013	Aug. 09, 2013	Aug. 09, 2013	Sep. 30, 2014	Aug. 09, 2013	Sep. 30, 2014	Apr. 09, 2014	Apr. 09, 2014
			item	Sanchez Oil And Gas Properties [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	La Salle Parrish Oil Wells [Member]	La Salle Parrish Oil Wells [Member]
						Common Class A [Member]	Common Class A [Member]	Common Class B [Member]	Common Class B [Member]		item
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Proceeds from sale of business	$63	'	'	'	'	'	'	'	'	'	'
Post-closing adjustments	4	'	'	'	'	'	'	'	'	'	'
Gain (Loss) on sale of business	'	-3.1	'	'	'	'	'	'	'	'	'
Purchase price for acquisition	'	'	'	'	30.4	'	'	'	'	1.4	'
Cash paid to SEP I	'	'	'	'	20.1	'	'	'	'	'	'
Units owned by third party	'	'	'	'	'	1,130,512	484,505	4,724,407	5,139,345	'	'
Units owned by third party, percentage of total shares	'	'	'	'	'	70.00%	100.00%	16.60%	17.90%	'	'
Amount borrowed from reserve based credit facility	'	'	'	$16.70	'	'	'	'	'	'	'
Number of wells acquired	'	'	67	'	'	'	'	'	'	'	9
Percentage of wells acquired	'	'	'	'	'	'	'	'	'	20.00%	'

Acquisitions_And_Divestiture_S

Acquisitions And Divestiture (Schedule Of Discontinued Operations) (Details) (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Discontinued Operations [Abstract]	'
Revenues	$2,304
Loss from discontinued operations	($2,686)

Acquisitions_And_Divestiture_E

Acquisitions And Divestiture (Estimated Values Of Assets Acquired And Liabilities Assumed) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Aug. 01, 2013
In Thousands, unless otherwise specified
Acquisitions And Divestiture [Abstract]	'	'	'
Oil and natural gas properties, equipment and facilities	$645,222	$639,156	$31,497
Asset retirement obligation	-10,085	-9,513	-1,088
Net assets acquired	'	'	$30,409

Acquisitions_And_Divestiture_S1

Acquisitions And Divestiture (Supplemental Pro Forma Information) (Details) (USD $)	3 Months Ended	9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013
Business Acquisition [Line Items]	'	'
Revenue	$16,067	$45,383
Loss from continuing operations	-998	-5,448
Discontinued operations	'	-2,686
Net loss	($998)	($8,134)
Common Class A [Member]	'	'
Business Acquisition [Line Items]	'	'
Loss from continuing operations per unit - Basic and diluted	($0.01)	($0.07)
Discontinued operations per unit - Basic and diluted	'	($0.03)
Net loss per unit - Basic and diluted	($0.01)	($0.10)
Weighted average units outstanding - Basic and diluted	1,614,964	1,614,918
Common Class B [Member]	'	'
Business Acquisition [Line Items]	'	'
Loss from continuing operations per unit - Basic and diluted	($0.03)	($0.19)
Discontinued operations per unit - Basic and diluted	'	($0.09)
Net loss per unit - Basic and diluted	($0.03)	($0.28)
Weighted average units outstanding - Basic and diluted	28,074,647	28,045,494

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	$5,529	$10,602
Risk Mgmt Liabilities	-245	'
Total Net Assets and Liabilities	5,284	10,602
Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	5,663	11,577
Risk Mgmt Liabilities	-379	-975
Total Net Assets and Liabilities	5,284	10,602
Netting Cash And Collateral [Member]	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	-134	-975
Risk Mgmt Liabilities	$134	$975

Derivative_And_Financial_Instr2

Derivative And Financial Instruments (Narrative) (Details) (USD $)	1 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2013	Sep. 30, 2013	Sep. 30, 2014
		MMBTU	item
		bbl
Derivative [Line Items]	'	'	'
Number of counterparties	'	'	2
Cost to liquidate derivative hedge	'	$0.30	'
Amount reduced from outstanding swap positions	'	1,041,814	'
Derivative contract swap, fixed price	'	3.66	'
Number of barrels of oil	'	58,157	'
Execution of amendment	0.2	'	'
Outstanding debt	30	'	'
Increase in interest rate swap settlement	$2.10	'	'
Swaps Covering 2013 NYMEX	'	'	'
Derivative [Line Items]	'	'	'
Derivative swaps liquidated	'	395,218	'
Swaps Covering 2014 NYMEX	'	'	'
Derivative [Line Items]	'	'	'
Derivative swaps liquidated	'	1,634,530	'
2014 Oil Trade [Member]	'	'	'
Derivative [Line Items]	'	'	'
Derivative contract swap, fixed price	'	98.1	'
2015 Oil Trade [Member]	'	'	'
Derivative [Line Items]	'	'	'
Derivative contract swap, fixed price	'	93.5	'

Derivative_And_Financial_Instr3

Derivative And Financial Instruments (Summary Of Hedges In Place) (Details)	9 Months Ended
	Sep. 30, 2014
	MMBTU
NYMEX 2014 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,610,000
Average Price	5.75
NYMEX 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	4,515,149
Average Price	4.25
NYMEX 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	3,795,032
Average Price	4.21
NYMEX [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	9,920,181
Centerpoint, ONEOK, Or Southern Star 2014 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,047,963
Average Price	0.39
Centerpoint, ONEOK, Or Southern Star [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,047,963
West Texas Intermediate 2014 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	73,005
Average Price	95.78
West Texas Intermediate 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	258,830
Average Price	91.04
West Texas Intermediate 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	214,970
Average Price	85.64
West Texas Intermediate [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	546,805
First Quarter [Member] | NYMEX 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,215,420
Average Price	4.25
First Quarter [Member] | NYMEX 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,010,633
Average Price	4.21
First Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	69,479
Average Price	90.99
First Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	57,420
Average Price	85.64
Second Quarter [Member] | NYMEX 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,153,487
Average Price	4.25
Second Quarter [Member] | NYMEX 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	967,290
Average Price	4.21
Second Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	66,183
Average Price	91.02
Second Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	54,879
Average Price	85.64
Third Quarter [Member] | NYMEX 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,096,023
Average Price	4.26
Third Quarter [Member] | NYMEX 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	923,541
Average Price	4.21
Third Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	63,025
Average Price	91.05
Third Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	52,474
Average Price	85.64
Fourth Quarter [Member] | NYMEX 2014 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,610,000
Average Price	5.75
Fourth Quarter [Member] | NYMEX 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,050,219
Average Price	4.26
Fourth Quarter [Member] | NYMEX 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	893,568
Average Price	4.21
Fourth Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	1,047,963
Average Price	0.39
Fourth Quarter [Member] | West Texas Intermediate 2014 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	73,005
Average Price	95.78
Fourth Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	60,143
Average Price	91.09
Fourth Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Derivatives [Line Items]	'
Volume (in MMBtu)	50,197
Average Price	85.64

Derivative_And_Financial_Instr4

Derivative And Financial Instruments (Fair Value for Risk Management Assets and Liabilities) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-current	$4,528	$9,141
Risk management assets-non-current	1,001	1,461
Total gross assets	5,663	11,577
Risk management liabilities-current	-245	'
Total gross liabilities	-379	-975
Total net assets and liabilities	5,284	10,602
Current Assets [Member] | Risk Management Commodity [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-current	4,617	10,043
Risk management liabilities-current	-334	-902
Noncurrent Assets [Member] | Risk Management Commodity [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-non-current	1,046	1,534
Risk management liabilities-non-current	($45)	($73)

Derivative_And_Financial_Instr5

Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	$7,671	($406)	($1,134)	$371
Oil And Natural Gas Sales [Member] | Realized Commodity [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	7,671	-406	-1,134	436
Interest Expense [Member] | Realized Interest Rate [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	'	'	'	($65)

Recovered_Sheet3

Oil and Natural Gas Properties (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Property, Plant and Equipment [Line Items]	'	'	'	'
Proceeds from sale of miscellaneous equipment and surplus inventory	$0.10	$0.10	$0.10	$0.10
Exploration costs	0	0	0	0
Furniture, Fixtures And Equipment [Member] | Minimum [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Useful life	'	'	'1 year	'
Furniture, Fixtures And Equipment [Member] | Maximum [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Useful life	'	'	'7 years	'
Buildings	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Useful life	'	'	'20 years	'
Pipeline and Gathering Systems [Member] | Minimum [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Useful life	'	'	'25 years	'
Pipeline and Gathering Systems [Member] | Maximum [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Useful life	'	'	'40 years	'
Texas And Louisiana Oil And Natural Gas Fields [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Non-cash impairment charges	'	'	$0.20	'

Recovered_Sheet4

Oil and Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Oil And Natural Gas Properties [Abstract]	'	'
Proved property	$642,923	$636,816
Unproved property	1,548	1,589
Total property costs	644,471	638,405
Materials and supplies	1,056	1,054
Land	751	751
Total	646,278	640,210
Less: Accumulated depreciation, depletion, amortization and impairments	-508,208	-495,215
Oil and natural gas properties and equipment, net	$138,070	$144,995

Oil_And_Natural_Gas_Properties2

Oil And Natural Gas Properties (Depletion, Depreciation, Amortization and Impairments) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Oil And Natural Gas Properties [Abstract]	'	'	'	'
DD&A of oil and natural gas-related assets	$4,836	$5,491	$13,206	$15,056
Asset impairments	43	'	237	'
Total	$4,879	$5,491	$13,443	$15,056

Debt_Details

Debt (Details) (USD $)

9 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

6-May-14

31-May-13

Apr. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Societe Generale [Member]

Societe Generale [Member]

Societe Generale [Member]

Societe Generale [Member]

OneWest Bank [Member]

Bank of Oklahoma [Member]

Letter of Credit [Member]

Minimum [Member]

Minimum [Member]

Minimum [Member]

Maximum [Member]

Maximum [Member]

Maximum [Member]

London Interbank Offered Rate (LIBOR) [Member]

ABR [Member]

London Interbank Offered Rate (LIBOR) [Member]

ABR [Member]

Line of Credit Facility [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reserve based credit facility maximum borrowing capacity

'

'

'

'

$350,000,000

'

'

'

$20,000,000

'

'

'

'

'

'

Maturity date of reserve-based credit facility

'

'

30-May-17

'

'

'

'

'

'

'

'

'

'

'

'

Borrowing base amount

'

'

70,000,000

70,000,000

55,000,000

37,500,000

'

'

'

'

'

'

'

'

'

Amount borrowed under credit facility

'

'

52,000,000

'

'

'

'

'

0

'

'

'

'

'

'

Commitment fee percentage

'

'

36.36%

'

'

'

36.36%

27.28%

'

'

'

'

'

'

'

Interest rate

'

'

'

'

'

'

'

'

'

'

2.50%

1.50%

'

3.50%

2.50%

Commitment fee on unutilized borrowing base

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total net debt adjusted to EBITDA

'

'

'

'

'

'

'

'

'

'

'

'

350.00%

'

'

Cash interest expense adjusted to EBITDA

'

'

'

'

'

'

'

'

'

250.00%

'

'

'

'

'

Consolidated current asset ratio

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

Ownership percentage by subsidiary

'

'

'

'

'

'

'

'

'

'

'

'

20.00%

'

'

Ownership percentage by person or group of persons

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

Exceeding of reserve-based credit facility over borrowing base

'

'

'

'

'

'

'

'

'

90.00%

'

'

'

'

'

Hedging of projected monthly production

'

'

'

'

'

'

'

'

'

'

'

'

115.00%

'

'

Heding of interest rate

'

'

'

'

'

'

'

'

'

'

'

'

90.00%

'

'

Outstanding debt under reserve-based credit facility

51,950,000

50,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Remaining borrowing capacity

18,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized debt issue costs

$800,000

$800,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Asset_Retirement_Obligation_Na

Asset Retirement Obligation (Narrative) (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'	'
Expenditures for abandonment	$0	$0
Legally restricted assets	$0	$0

Asset_Retirement_Obligation_Re

Asset Retirement Obligation (Reconciliation of Asset Retirement Obligation) (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'	'	'	'	'
Asset retirement obligation, beginning balance	'	'	$9,513	$7,665	$7,665
Liabilities added from acquisitions	'	'	79	'	1,088
Liabilities added from drilling	'	'	42	'	244
Settlements	'	'	'	'	-3
Accretion expense	151	163	451	409	519
Asset retirement obligation, ending balance	$10,085	'	$10,085	'	$9,513

Commitments_And_Contingencies_

Commitments And Contingencies (Details) (USD $)	9 Months Ended			9 Months Ended	12 Months Ended	9 Months Ended
	Sep. 30, 2014	Jun. 26, 2014	Apr. 10, 2014	Sep. 30, 2014	Dec. 31, 2006	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
				Constellation Energy Partners Management [Member]	CEPH [Member]	Common Class A [Member]	Common Class A [Member]	Common Class B [Member]	Common Class B [Member]
							Constellation Energy Partners Management [Member]		Constellation Energy Partners Management [Member]
Class Of Stock [Line Items]	'	'	'	'	'	'	'	'	'
Percentage of shares to be transferred	'	'	'	'	'	'	100.00%	'	'
Shares to be transferred	'	'	'	'	'	'	'	'	414,938
Amount received from units transferred	'	'	'	'	'	'	$800,000	'	$1,000,000
Settlement payment	'	'	'	'	'	'	'	'	6,500,000
Maximum backstop payment	'	'	'	5,000,000	'	'	'	'	'
Amount received from directors and officers insurance policy	'	'	1,250,000	'	'	'	'	'	'
Proceeds from sales of shares	'	'	'	'	8,000,000	'	'	'	'
Quarterly dividend amount	'	'	'	'	333,333.33	'	'	'	'
Dividend payment period	'	'	'	'	'6 years	'	'	'	'
Amount paid for repurchased shares	'	$1,650,000	'	'	'	'	'	'	'

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	0 Months Ended		9 Months Ended			0 Months Ended	9 Months Ended	0 Months Ended	9 Months Ended
	Jul. 01, 2014	8-May-14	Sep. 30, 2014	8-May-14	Sep. 30, 2014	Aug. 09, 2013	Sep. 30, 2014	Aug. 09, 2013	Sep. 30, 2014
					Sanchez Oil And Gas Corporation [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]	Sanchez Energy Partners I [Member]
						Common Class A [Member]	Common Class A [Member]	Common Class B [Member]	Common Class B [Member]
Related Party Transaction [Line Items]	'	'	'	'	'	'	'	'	'
Units owned by third party	'	'	'	'	'	1,130,512	484,505	4,724,407	5,139,345
Units owned by third party, percentage of total shares	'	'	'	'	'	70.00%	100.00%	16.60%	17.90%
Ownership percentage in company by related party	'	'	'	'	19.20%	'	'	'	'
Percent of value of properties held used to compute quarterly fee	'	'	'	0.38%	'	'	'	'	'
Administrative fee	'	$1,000,000	'	'	'	'	'	'	'
Administrative fee paid	500,000	500,000	'	'	'	'	'	'	'
Maximum asset acquisition, disposition and financing fee	'	2.00%	'	'	'	'	'	'	'
Term of Services Agreement	'	'	'10 years	'	'	'	'	'	'
Term of Services Agreement renewal	'	'	'10 years	'	'	'	'	'	'
Length of time after In-Service Date before Agreement can be terminated	'	'	'24 months	'	'	'	'	'	'
Termination fee	'	5,000,000	'	'	'	'	'	'	'
Transaction value, percentage	'	5.00%	'	'	'	'	'	'	'
Amount paid under Services Agreement	'	'	$800,000	'	'	'	'	'	'

UnitBased_Compensation_Narrati

Unit-Based Compensation (Narrative) (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Unit-Based Compensation [Abstract]	'	'
Non-cash compensation expense	$1.20	$0.80

UnitBased_Compensation_Schedul

Unit-Based Compensation (Schedule Of Units Granted) (Details) (USD $)	3 Months Ended			9 Months Ended	12 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
2009 Omnibus Incentive Compensation Plan [Member]	'	'	'	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'	'	'	'
Number of Restricted Units, Outstanding	400,414	107,645	336,551	336,551	'
Number of Restricted Units, Vested	-236,809	-37,653	-171,692	-1,476,269	-1,030,115
Number of Restricted Units, Granted	'	346,403	'	1,562,687	1,366,666
Number of Restricted Units, Returned/Cancelled	-77,187	-15,981	-57,214	'	'
Number of Restricted Units, Outstanding	86,418	400,414	107,645	86,418	336,551
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$2.39	$3.20	$3.29	$3.29	'
Weighted Averaged Grant Date Fair Value Per Unit, Vested	$2.46	$2.44	$3.33	'	'
Weighted Averaged Grant Date Fair Value Per Unit, Granted	'	$2.44	'	'	'
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled	$2.44	$3.44	$3.33	'	'
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$3.15	$2.39	$3.20	$3.15	$3.29
Long Term Incentive Plan [Member]	'	'	'	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'	'	'	'
Number of Restricted Units, Outstanding	103,142	21,892	43,776	43,776	'
Number of Restricted Units, Vested	-60,938	-22,028	-16,415	-402,339	-302,958
Number of Restricted Units, Granted	'	103,278	'	424,231	346,734
Number of Restricted Units, Returned/Cancelled	-20,312	'	-5,469	'	'
Number of Restricted Units, Outstanding	21,892	103,142	21,892	21,892	43,776
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$2.53	$2.87	$2.87	$2.87	'
Weighted Averaged Grant Date Fair Value Per Unit, Vested	$2.44	$2.44	$2.87	'	'
Weighted Averaged Grant Date Fair Value Per Unit, Granted	'	$2.44	'	'	'
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled	$2.44	'	$2.87	'	'
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$2.87	$2.53	$2.87	$2.87	$2.87

Members_Equity_Details

Members' Equity (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

In Thousands, except Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Long Term Incentive Plan [Member]

Long Term Incentive Plan [Member]

Long Term Incentive Plan [Member]

Long Term Incentive Plan [Member]

Long Term Incentive Plan [Member]

2009 Omnibus Incentive Compensation Plan [Member]

2009 Omnibus Incentive Compensation Plan [Member]

2009 Omnibus Incentive Compensation Plan [Member]

2009 Omnibus Incentive Compensation Plan [Member]

2009 Omnibus Incentive Compensation Plan [Member]

Common Class A [Member]

Common Class A [Member]

Common Class B [Member]

Common Class B [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares units outstanding

'

'

'

'

'

'

'

'

'

'

'

'

484,505

1,615,017

28,735,703

28,462,185

Unvested restricted common stock issued

'

'

21,892

103,142

21,892

21,892

43,776

86,418

400,414

107,645

86,418

336,551

'

'

108,310

'

Common units granted

'

'

'

103,278

'

424,231

346,734

'

346,403

'

1,562,687

1,366,666

'

'

'

'

Common units available under incentive plan

'

'

450,000

'

'

450,000

450,000

1,650,000

'

'

1,650,000

1,650,000

'

'

'

'

Common units vested

'

'

60,938

22,028

16,415

402,339

302,958

236,809

37,653

171,692

1,476,269

1,030,115

'

'

'

'

Common units tendered for tax withholding purpose

139,810

160,182

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Units tendered by employees for tax withholding

$200

$415

'

'

'

'

'

'

'

'

'

'

'

'

$415

'