Evolve Transition Infrastructure (SNMP) 10-Q 14 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 08, 2013
Document And Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'cep	'
Entity Registrant Name	'Constellation Energy 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	'	28,463,746

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets	'	'
Cash and cash equivalents	$3,724	$1,959
Accounts receivable	6,784	5,615
Prepaid expenses	1,419	1,309
Risk management assets (see Note 5)	12,196	17,965
Current assets from discontinued operations	'	1,886
Total current assets	24,123	28,734
Oil and natural gas properties (See Note 6)	'	'
Oil and natural gas properties, equipment and facilities	638,231	594,020
Material and supplies	846	771
Less accumulated depreciation, depletion, amortization, and impairments	-489,083	-474,669
Net oil and natural gas properties	149,994	120,122
Other assets	'	'
Debt issue costs (net of accumulated amortization of $9,003 and $7,775, respectively)	865	1,168
Risk management assets (see Note 5)	4,404	7,431
Other non-current assets	4,109	3,194
Long-term assets from discontinued operations	'	67,373
Total assets	183,495	228,022
Current liabilities	'	'
Accounts payable	46	480
Accrued liabilities	8,357	7,174
Royalty payable	1,364	1,418
Risk management liabilities (see Note 5)	'	523
Debt	'	50,000
Current liabilities from discontinued operations	'	1,578
Total current liabilities	9,767	61,173
Other liabilities	'	'
Asset retirement obligation	9,325	7,665
Risk management liabilities (see Note 5)	'	637
Other non-current liabilities	1,953	589
Debt	50,700	34,000
Other long-term liabilities from discontinued operations	'	7,692
Total liabilities	71,745	111,756
Commitments and contingencies (See Note 9)	'	'
Members' equity	'	'
Total members' equity	111,750	116,266
Total liabilities and members' equity	183,495	228,022
Common Class A	'	'
Members' equity	'	'
Limited partners' capital account	2,847	2,326
Common Class B	'	'
Members' equity	'	'
Limited partners' capital account	$108,903	$113,940

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Debt issue costs, accumulated amortization	9,003	7,775
Common Class A	'	'
Share units authorized	1,615,017	483,418
Share units issued	1,615,017	483,418
Shares units outstanding	1,615,017	483,418
Common Class B	'	'
Share units authorized	28,848,785	24,124,378
Share units issued	28,463,746	23,687,507
Shares units outstanding	28,463,746	23,687,507

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, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues	'	'	'	'
Natural gas sales	$7,328	$1,898	$18,745	$23,243
Oil and liquids sales	4,803	1,379	13,874	9,847
Total revenues (see Note 5)	12,131	3,277	32,619	33,090
Operating expenses:	'	'	'	'
Lease operating expenses	5,191	4,869	13,332	14,727
Cost of sales	323	287	1,122	923
Production taxes	731	374	1,840	1,141
General and administrative	3,015	4,014	11,156	11,555
Loss on sale of assets	31	'	8	'
Depreciation, depletion, and amortization	5,491	2,373	15,056	7,078
Asset impairments	'	'	'	107
Accretion expense	163	116	409	345
Total operating expenses	14,945	12,033	42,923	35,876
Other expenses (income)	'	'	'	'
Interest expense	420	1,534	2,636	4,590
Other expenses (income)	23	-21	-149	-114
Total other expenses	443	1,513	2,487	4,476
Total expenses	15,388	13,546	45,410	40,352
Loss from continuing operations	-3,257	-10,269	-12,791	-7,262
Loss from discontinued operations	'	-894	-2,686	-3,026
Net loss	-3,257	-11,163	-15,477	-10,288
Change in fair value of commodity hedges	'	63	'	151
Cash settlement of commodity hedges	'	-1,722	'	-4,367
Other comprehensive loss	'	-1,659	'	-4,216
Comprehensive loss	($3,257)	($12,822)	($15,477)	($14,504)
Loss per unit (see Note 2)	'	'	'	'
Loss from continuing operations per unit-Basic	($0.12)	($0.42)	($0.51)	($0.30)
Loss from discontinued operations per unit-Basic	'	($0.04)	($0.11)	($0.13)
Net loss per unit-Basic	($0.12)	($0.46)	($0.62)	($0.43)
Units outstanding-Basic	26,888,303	24,169,012	24,840,502	24,171,669
Loss from continuing operations per unit-Diluted	($0.12)	($0.42)	($0.51)	($0.30)
Loss from discontinued operations per unit-Diluted	'	($0.04)	($0.11)	($0.13)
Net loss per unit-Diluted	($0.12)	($0.46)	($0.62)	($0.43)
Units outstanding-Diluted	26,888,303	24,169,012	24,840,502	24,171,669
Distributions declared and paid per unit	'	'	'	'

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Cash Flows (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities:	'	'
Net loss	($15,477)	($10,288)
Adjustments to reconcile net loss to cash provided by operating activities	'	'
Depreciation, depletion and amortization	15,056	7,078
Asset impairments (see Note 6)	'	107
Amortization of debt issuance costs	1,228	974
Accretion expense	409	345
Equity earnings in affiliate	-224	-129
Gain from disposition of property and equipment	8	'
Bad debt expense	44	26
Loss from mark-to-market activities	7,635	7,756
Unit-based compensation programs	828	1,163
Discontinued operations	2,686	3,026
Changes in Assets and Liabilities:	'	'
(Increase) decrease in accounts receivable	-1,212	1,004
(Increase) decrease in prepaid expenses	-110	278
Increase in other assets	-1,107	-600
Increase (decrease) in accounts payable	-434	279
Decrease in accrued liabilities	-1,614	-2,699
Decrease in royalty payable	-54	-47
Increase in other liabilities	1,114	507
Net cash provided by continuing operations	8,776	8,780
Net cash provided by discontinued operations	1,062	2,655
Net cash provided by operating activities	9,838	11,435
Cash flows from investing activities:	'	'
Cash paid for acquisitions, net of cash acquired	-20,221	-75
Development of oil and natural gas properties	-12,564	-10,309
Proceeds from sale of assets	58,987	1,505
Distributions from equity affiliate	135	150
Net cash provided by (used in) continuing operations	26,337	-8,729
Net cash used in discontinued operations	'	-147
Net cash provided by (used in) investing activities	26,337	-8,876
Cash flows from financing activities:	'	'
Proceeds from issuance of debt	16,894	'
Repayment of debt	-50,194	-10,000
Units tendered by employees for tax withholdings	-185	-199
Debt issue costs	-925	-14
Net cash used in continuing operations	-34,410	-10,213
Net cash used in discontinued operations	'	'
Net cash used in financing activities	-34,410	-10,213
Net (decrease) increase in cash and cash equivalents	1,765	-7,654
Cash and cash equivalents, beginning of period	1,959	17,176
Cash and cash equivalents, end of period	3,724	9,522
Supplemental disclosures of cash flow information:	'	'
Change in accrued capital expenditures	333	34
Cash received during the period for interest	'	1
Cash paid during the period for interest	($1,405)	($2,812)

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Changes in Members' Equity (USD $)	Common Class A	Common Class B	Accumulated Other Comprehensive Income (Loss)	Total
In Thousands, except Share data
Beginning Balance at Dec. 31, 2012	$2,326	$113,940	'	$116,266
Beginning Balance (in shares) at Dec. 31, 2012	483,418	23,687,507	'	'
Distributions	'	'	'	'
Units tendered by employees for tax (Shares)	-2,853	-139,810	'	'
Units tendered by employees for tax	-4	-181	'	-185
Unit-based compensation programs (in shares)	3,940	191,642	'	'
Unit-based compensation programs	17	811	'	828
Unit issuance cost (in shares)	1,130,512	4,724,407	'	'
Unit issuance cost	818	9,500	'	10,318
Net loss	-310	-15,167	'	-15,477
Ending Balance at Sep. 30, 2013	$2,847	$108,903	'	$111,750
Ending Balance (in shares) at Sep. 30, 2013	1,615,017	28,463,746	'	'

Organization_And_Basis_Of_Pres

Organization And Basis Of Presentation	9 Months Ended
	Sep. 30, 2013
Organization And Basis Of Presentation [Abstract]	'
Organization And Basis Of Presentation	'
	1. ORGANIZATION AND BASIS OF PRESENTATION
	Organization
	Constellation Energy Partners LLC (CEP, we, us, our or the Company) 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 “CEP”. Through subsidiaries, PostRock Energy Corporation (NASDAQ: PSTR) (PostRock), Exelon Corporation (NYSE: EXC) (Exelon) and Sanchez Oil & Gas Corporation (SOG) own a portion of our outstanding units. As of September 30, 2013, Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned 484,505 of our Class A units and 5,918,894 of our Class B common units. Constellation Energy Partners Holdings, LLC (CEPH), a subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests. Sanchez Energy Partners I, LP (SEP I), a subsidiary of SOG, owned 1,130,512, or 70%, of our Class A units and 4,724,407 of our Class B common units.
	We are currently focused on the acquisition, development and production of oil and natural gas properties, as well as midstream assets.  Our proved reserves are 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.
	Basis of Presentation
	These unaudited condensed consolidated financial statements include the accounts of CEP 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 CEP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2012, which was filed with the SEC on March 11, 2013, and amended by Amendment No. 1 thereto filed with the SEC on April 18, 2013.
	Use of Estimates
	The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes.  These estimates and the underlying assumptions affect the amounts of assets and liabilities reported disclosures about contingent assets and liabilities and reported amounts of revenues and expenses.  The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (NGLs); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing 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 amounts in the prior period financial statements have been reclassified to conform to the current period presentation.  These reclassifications had no impact on the previously reported net income (loss) for any periods.
	New Accounting Pronouncements
	In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Updates (ASU) No. 2011-11, Disclosures about Offsetting Assets and Liabilities, which requires additional disclosures for financial and derivative instruments that are either (1) offset in accordance with either Accounting Standards Codification (ASC) 210-20-45 or ASC 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement, regardless of whether they are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The guidance was effective beginning on or after January 1, 2013, and primarily impacts the disclosures associated with our commodity and interest rate derivatives. Implementation of this guidance did not have any material impact on our consolidated financial position, results of operations or cash flows.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2013
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, 2012.
	Earnings per Unit
	Basic earnings per unit (EPU) are computed by dividing net income attributable to unitholders by the weighted average number of units outstanding during each period. At September 30, 2013, we had 1,615,017 Class A units and 28,463,746 Class B common units outstanding. Of the Class B common units, 386,579 units are restricted unvested common units granted and outstanding.
	The following table presents earnings per common unit amounts (in thousands, except per unit data):
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Numerator:
	Loss from continuing operations allocable to unitholders	$	-3,257	$	-10,269	$	-12,791	$	-7,262
	Loss from discontinued operations allocable to unitholders		—		-894		-2,686		-3,026
	Loss allocable to unitholders	$	-3,257	$	-11,163	$	-15,477	$	-10,288
	Denominator:
	Weighted average units outstanding		26,888,303		24,169,012		24,840,502		24,171,669
	Net earnings per unit:
	Basic:
	Loss from continuing operations allocable to unitholders	$	-0.12	$	-0.42	$	-0.51	$	-0.3
	Loss from discontinued operations allocable to unitholders		—		-0.04		-0.11		-0.13
	Loss allocable to unitholders	$	-0.12	$	-0.46	$	-0.62	$	-0.43
	Diluted:
	Loss from continuing operations allocable to unitholders	$	-0.12	$	-0.42	$	-0.51	$	-0.3
	Loss from discontinued operations allocable to unitholders		—		-0.04		-0.11		-0.13
	Loss allocable to unitholders	$	-0.12	$	-0.46	$	-0.62	$	-0.43
	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, 2013, and our checks-in-transit reported in accounts payable were $0.5 million at December 31, 2012.
	We have established an escrow account for $0.6 million related to a vendor dispute, which is included in other non-current assets in our consolidated balance sheets at September 30, 2013, and December 31, 2012. This amount will remain in the escrow account until the dispute has been resolved. We also have an escrow account for approximately $1.2 million related to the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama, which is included in other non-current assets in our consolidated balance sheets at September 30, 2013. These funds will be held in escrow for a period up to twenty-four months, ending February 28, 2015, pending certain closing conditions.

Acquisition_And_Divestiture

Acquisition And Divestiture	9 Months Ended
	Sep. 30, 2013
Acquisition And Divestiture [Abstract]	'
Acquisition And Divestiture	'
	3. ACQUISITION AND DIVESTITURE
	Sale of Robinson’s Bend Field Assets
	On February 28, 2013, we sold our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments.  We recorded a loss on the sale of approximately $3.1 million in the three months ended March 31, 2013.
	Acquisition of Oil, Natural Gas and Natural Gas Liquids Properties From SEP I
	On August 9, 2013, we acquired oil, natural gas and natural gas liquids 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 represents 70.0% of the total Class A units and 4,724,407 Class B units, which represents 16.6% of the total Class B.  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 include 67 producing wells in Texas and Louisiana.  The primary factors considered by management in acquiring the Sep I properties include 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 allocation of the purchase price is preliminary and includes estimates.  This preliminary allocation is based on information that was available to management at the time these condensed consolidated financial statements were prepared and takes into account current market conditions and estimated market prices for oil and natural gas.  Management has not yet had the opportunity to complete its assessment of fair values of the assets acquired.  In addition, the purchase price could change materially as management finalizes adjustments to the purchase price provided for by the purchase and sale agreement.  Accordingly, the allocation may change materially as additional information becomes available and is assessed by management.
	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		$	30,409
	Asset retirement obligation			-1,088
	Net assets acquired		$	29,321
	We will finalize the purchase price allocation within one year of the acquisition date.
	We have accounted for our acquisition of oil and natural gas properties using the purchase method of accounting for business combinations, and therefore we have 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 are based on inputs that are 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.
	Results of Operations and Pro Forma Information
	The following table sets forth revenues and lease operating expenses attributable to the SEP I properties acquired (in thousands):
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013			2012		2013		2012
	Revenue	$	3,936		$	4,516	$	12,764	$	15,904
	Lease Operating Expenses	$	797		$	1,184	$	3,018	$	3,795
	We have determined that the presentation of net income attributable to the SEP I properties is impracticable due to the integration of the related operations upon acquisition.
	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, 2012.  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, 2012, nor is such information indicative of any expected future results of operations.
		Pro Forma					Pro Forma
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
	(In thousands)	2013			2012		2013		2012
	Revenue	$	16,067		$	7,793	$	45,383	$	48,994
	Net Loss	$	-1,433		$	-8,370	$	-8,569	$	-186
	Basic loss per unit	$	-0.05		$	-0.28	$	-0.29	$	-0.01
	Diluted loss per unit	$	-0.05		$	-0.28	$	-0.29	$	-0.01

Fair_Value_Messurements

Fair Value Messurements	9 Months Ended
	Sep. 30, 2013
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, 2013 (in thousands):
		Fair Value Measurements at September 30, 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		30-Sep-13
	Risk Mgmt Assets	$	—	$	18,225	$	—	$	-1,625	$	16,600
	Risk Mgmt Liabilities		—		-1,625		—		1,625		—
	Total Net Assets and Liabilities	$	—	$	16,600	$	—	$	—	$	16,600
	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, 2012 (in thousands):
		Fair Value Measurements at December 31, 2012
		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-12
	Risk Mgmt Assets	$	—	$	31,030	$	—	$	-5,634	$	25,396
	Risk Mgmt Liabilities		—		-6,794		—		5,634		-1,160
	Total Net Assets and Liabilities	$	—	$	24,236	$	—	$	—	$	24,236
	As of September 30, 2013, 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, 2013
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 elected to designate only a portion 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, 2013, 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
	2013													1,691,540	$	6.18	1,691,540	$	6.18
	2014	1,575,000		$	5.75		1,592,500		$	5.75	1,610,000	$	5.75	1,610,000	$	5.75	6,387,500	$	5.75
	2015	1,011,055		$	4.27		971,604		$	4.27	938,968	$	4.27	908,492	$	4.27	3,830,119	$	4.27
	2016	441,492		$	4.31		426,825		$	4.31	414,329	$	4.31	403,684	$	4.31	1,686,330	$	4.31
																	13,595,489
	MTM Fixed Price Basis Swaps– CenterPoint Energy Gas Transmission (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 $
	2013													1,223,985	$	0.39	1,223,985	$	0.39
	2014	1,178,422		$	0.39		1,133,022		$	0.39	1,084,270	$	0.39	1,047,963	$	0.39	4,443,677	$	0.39
																	5,667,662
	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
	2013													65,256	$	99.93	65,256	$	99.93
	2014	60,928		$	94.64		57,154		$	94.67	53,797	$	94.72	50,597	$	94.80	222,476	$	94.70
	2015	47,747		$	90.95		45,065		$	91.00	42,672	$	91.04	40,329	$	91.10	175,813	$	91.02
	2016	17,957		$	85.50		16,985		$	85.50	16,048	$	85.50	15,127	$	85.50	66,117	$	85.50
																	529,662
	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-13			31-Dec-12
	Commodity – MTM		Risk management assets - current		$	13,581		$	19,005
	Commodity – MTM		Risk management assets  - non-current			4,644			12,025
			Total gross assets			18,225			31,030
	Commodity – MTM		Risk management assets – current			-1,385			-1,040
	Commodity – MTM		Risk management assets – non-current			-240			-946
	Commodity – MTM		Rick management liabilities – current			—			-523
	Commodity – MTM		Risk management liabilities – non-current			—			-637
	Interest Rate - MTM		Risk management assets – non-current			—			-3,648
			Total gross liabilities			-1,625			-6,794
			Total net assets and liabilities		$	16,600		$	24,236
	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		2013			2012
	Commodity – MTM – Unrealized		Natural gas sales		$	-2,995		$	-8,746
	Commodity – MTM – Unrealized		Oil and liquids sales			-1,350			-1,412
	Commodity – MTM – Realized		Natural gas sales			4,174			5,934
	Commodity – MTM – Realized		Oil and liquids sales			-235			302
	Interest Rate – MTM – Unrealized		Interest expense			—			92
	Interest Rate – MTM - Realized		Interest expense			—			-460
			Total		$	-406		$	-4,290
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Nine Months Ended September 30,
	Derivative Type		in Income		2013			2012
	Commodity – MTM – Unrealized		Natural gas sales		$	-10,124		$	-9,329
	Commodity – MTM – Unrealized		Oil and liquids sales			-1,160			876
	Commodity – MTM – Realized		Natural gas sales			11,448			19,200
Commodity – MTM – Realized		Oil and liquids sales			272			426
Interest Rate – MTM – Unrealized		Interest expense			3,648			697
Interest Rate – MTM - Realized		Interest expense			-3,713			-1,746
		Total		$	371		$	10,124
				Amount of Gain/(Loss) Reclassified from
		Location of Gain/(Loss) for		AOCI into Income – Effective
		Effective and Ineffective		For the Three Months Ended September 30,
Derivative Type		Portion of Derivative in Income		2013			2012
Commodity – Cash Flow		Natural gas sales		$	—		$	1,722
		Total		$	—		$	1,722
				Amount of Gain/(Loss) Reclassified from
		Location of Gain/(Loss) for		AOCI into Income – Effective
		Effective and Ineffective		For the Nine Months Ended September 30,
Derivative Type		Portion of Derivative in Income		2013			2012
Commodity – Cash Flow		Natural gas sales		$	—		$	4,367
		Total		$	—		$	4,367
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, 2013, the impact of non-performance credit risk on the valuation of our net assets from counterparties was not significant.  At September 30, 2012, the impact of non-performance credit risk on the valuation of our net assets from counterparties was $0.2 million, of which $0.1 million was reflected as a decrease to our non-cash mark-to-market gain and $0.1 million was reflected in our accumulated other comprehensive loss.
Under the terms of our reserve-based credit facility, we have agreed to hedge 100% of our reasonably estimated projected natural gas production for 2015 and 2016.  All of the required 2015 hedges are in place, and we have agreed to enter into the remaining 2016 hedges on or before December 31, 2013.  In the event that the 2016 hedges are not in place by December 31, 2013, our borrowing base will automatically be reduced by the shortfall of actual hedges as compared to 50% of the reasonably estimated projected natural gas production, not to exceed an amount equal to $3.0 million times the calculated percentage of hedging shortfall.  We expect to enter into the 2016 hedges prior to December 31, 2013.
Hedge Liquidation, Repositioning and Novation
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.  These transactions ensure 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, 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, 2013
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, 2013		December 31, 2012
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	635,993	$	591,889
	Unproved property		1,487		1,380
	Total property costs		637,480		593,269
	Materials and supplies		846		771
	Land		751		751
	Total		639,077		594,791
	Less: Accumulated depreciation, depletion, amortization and
	impairments		-489,083		-474,669
	Oil and natural gas properties and equipment, net	$	149,994	$	120,122
	Depletion, depreciation, amortization and impairments consisted of the following (in thousands):
		Nine Months Ended September 30,
		2013		2012
	DD&A of oil and natural gas-related assets	$	15,056	$	7,078
	Asset Impairments		—		107
	Total	$	15,056	$	7,185
	Impairment of Oil and Natural Gas Properties and Other Non-Current Assets
	For the three months ended September 30, 2013, we did not have an impairment to record. In March 2012, we recorded a total non-cash impairment charge of approximately $0.1 million to impair certain of our wells in the Woodford Shale. This 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. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 2 inputs in the fair value hierarchy. Significant assumptions in valuing the proved reserves included the reserve quantities, anticipated operating costs, anticipated production taxes, future expected oil and natural gas prices and basis differentials, anticipated production declines and an appropriate discount rate commensurate with the risk of the underlying cash flow estimates for the properties of 10.0%. The impairment was primarily caused by the impact of lower future expected oil and natural gas prices on future expected cash flows during the first quarter of 2012. After the impairments, the remaining net capitalized costs subject to impairment in the Woodford Shale was approximately $3.6 million. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the risk of lower future oil and natural gas prices. These asset impairments have no impact on our cash flows, liquidity position, or debt covenants.
	Asset Sales
	On February 28, 2013, we sold our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments, and recorded a loss on the sale of approximately $3.1 million. These assets were classified as discontinued operations in the first quarter of 2013. In July 2013, we paid the purchaser $1.1 million based on the final settlement statement. See Note 13 for additional information.
	In the nine months ended September 30, 2013, we also sold miscellaneous surplus equipment for less than $0.1 million resulting in an immaterial gain on the asset sale. In the nine months ended September 30, 2012, we sold our interests in 14 gross non-operated oil wells in Kansas and Nebraska for approximately $1.4 million in cash, resulting in an immaterial loss on the asset sale.

Debt

Debt	9 Months Ended
	Sep. 30, 2013
Debt [Abstract]	'
Debt	'
	7. DEBT
	Reserve-Based Credit Facility
	In May 2013, we amended our existing reserve-based credit facility. This amendment increased our borrowing capacity, extended the maturity date and changed the lenders participating in the facility.
	At September 30, 2013, we had a $350.0 million reserve-based credit facility with Societe Generale as administrative and collateral agent and a syndicate of lenders. This reserve-based credit facility had a borrowing base of $55.0 million and matures on May 30, 2017. At September 30, 2013, we had $50.7 million in borrowings outstanding, which is reflected as a non-current liability on our balance sheet. 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 lenders and their percentage commitments in the reserve-based credit facility are Societe Generale (36.36%), OneWest Bank, FSB (36.36%), and BOKF NA, dba Bank of Oklahoma (27.28%).
	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 are 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 and the interest rate on our borrowings.
	Debt Issue Costs
	During the nine months ended September 30, 2013, we accelerated the amortization of approximately $0.7 million of debt issue costs as a result of amendments to our reserve-based credit facility. Accelerated amortization of the debt issue costs was required as the syndicate of lenders participating in the reserve-based credit facility changed. As of September 30, 2013, our unamortized debt issue costs were approximately $0.9 million. These costs are being amortized over the life of our reserve-based credit facility.
	Funds Available for Borrowing
	As of September 30, 2013 and 2012, we had $50.7 million and $88.4 million, respectively, in outstanding debt under our reserve-based credit facility. As of September 30, 2013, we had $4.3 million borrowing capacity available under our reserve-based credit facility.
	Compliance with Debt Covenants
	At September 30, 2013, we were in compliance with the financial covenants contained in our reserve-based credit facility.

Asset_Retirement_Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2013
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,
		2013		2012
	Asset retirement obligation, beginning balance	$	7,665	$	7,052
	Liabilities incurred		1,254		162
	Liabilities settled		-3		-8
	Accretion expense		409		459
	Asset retirement obligation, ending balance	$	9,325	$	7,665
	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, 2013, and December 31, 2012, 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, 2013
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 CEPM, Gary M. Pittman and John R. Collins against the Company, certain of its officers and managers, SOG and SEP I in connection with the Company’s closing on August 9, 2013 of the purchase of oil and gas properties from SEP I and the issuance of units in connection therewith.  The plaintiffs contend, 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 the bad faith conduct of the other defendants and interfered with CEPM’s contractual rights under the Company’s operating agreement. The plaintiffs allege 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 allege aiding and abetting and tortuous interference claims against SOG, SEP I and our current Class A managers.  The plaintiffs seek, 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 has sole voting power with respect to the outstanding Class A units, declaratory relief that the Company’s officers and managers have breached fiduciary and contractual duties and are not entitled to indemnification from the Company as a result thereof, and monetary damages.  The lawsuit is currently in the discovery phase with a hearing on the plaintiff’s application for an injunction seeking to enjoin the Company’s December 5, 2013 annual meeting of unitholders scheduled for December 2, 2013, and the trial scheduled for December 16, 17 and18 in Wilmington, Delaware.  The Company believes that the allegations contained in the lawsuit are without merit and intends to vigorously defend itself and its officers and managers against the claims raised in the complaint.

Related_Party_Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2013
Related Party Transactions [Abstract]	'
Related Party Transations	'
	10. RELATED PARTY TRANSACTIONS
	Unit Ownership
	PostRock, Exelon and SOG, through subsidiaries, own a portion of our outstanding units. As of September 30, 2013, CEPM, a subsidiary of PostRock, owned 484,505 of our Class A units and 5,918,894 of our Class B common units. CEPH, a subsidiary of Exelon, owned all of our Class C management incentive interests and all of our Class D interests as of September 30, 2013. SEP I, a subsidiary of SOG, owned 1,130,512, or 70%, of our Class A units and 4,724,407 of our Class B common units.
	Class C Management Incentive Interests
	CEPH, a subsidiary of Exelon, held all of the Class C management incentive interests in CEP as of September 30, 2013. These management incentive interests represent the right to receive 15% of quarterly distributions of available cash from operating surplus after the Target Distribution (as defined in our operating agreement) has been achieved and certain other tests have been met. None of these applicable tests have yet to be met and CEPH has not been entitled to receive any management incentive interest distributions.

Compensation

Compensation	9 Months Ended
	Sep. 30, 2013
Compensation [Abstract]	'
Compensation	'
	11. COMPENSATION
	We recognized approximately $0.8 million and $1.2 million of non-cash compensation expense related to our unit-based compensation plans in the nine months ended September 30, 2013, and September 30, 2012, respectively. As of September 30, 2013, we had approximately $0.6 million in unrecognized compensation expense related to our unit-based non-cash compensation plans expected to be recognized through the first quarter of 2015.
	In the nine months ended September 30, 2013, we incurred one-time severance costs of approximately $1.0 million. This one-time charge was reflected as general and administrative expenses and was composed of approximately $0.8 million in cash compensation expense and approximately $0.2 million in non-cash compensation expense related to accelerated vesting under our unit-based compensation plans.

Distributions_To_Unitholders

Distributions To Unitholders	9 Months Ended
	Sep. 30, 2013
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, 2013
Members' Equity [Abstract]	'
Members' Equity	'
	13. MEMBERS’ EQUITY
	2013 Equity
	At September 30, 2013, we had 1,615,017 Class A units and 28,463,746 Class B common units outstanding, which included 43,776 unvested restricted common units issued under our Long-Term Incentive Plan and 342,803 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan.
	At September 30, 2013, we had granted 346,734 common units of the 450,000 common units available under our Long-Term Incentive Plan. Of these grants, 302,958 have vested.
	At September 30, 2013, we had granted 1,368,227 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants,  1,025,424 have vested.
	For the nine months ended September 30, 2013, 139,810 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, have been returned to their respective plan and are available for future grants.
	2012 Equity
	At September 30, 2012, we had 483,304 Class A units and 23,681,878 Class B common units outstanding, which included 94,914 unvested restricted common units issued under our Long-Term Incentive Plan and 665,840 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan.
	At September 30, 2012, we had granted 336,599 common units of the 450,000 common units available under our Long-Term Incentive Plan. Of these grants, 241,685 have vested. We also granted an additional 76,046 performance units under our Long-Term Incentive Plan that are subject to performance conditions which vested on January 2, 2013.
	At September 30, 2012, we had granted 1,320,901 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 655,061 have vested. We also granted an additional 323,194 performance units under our 2009 Omnibus Incentive Compensation Plan that are subject to performance conditions which vested on January 1, 2013.
	For the nine months ended September 30, 2012, 89,271 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, have been returned to their respective plan and are available for future grants.

Discontinued_Operations

Discontinued Operations	9 Months Ended
	Sep. 30, 2013
Discontinued Operations [Abstract]	'
Discontinued Operations	'
	14. DISCONTINUED OPERATIONS
	On January 31, 2013, our Board of Managers authorized the sale of the two entities that owned all of our natural gas properties and inventory in the Robinson’s Bend Field in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments. On February 28, 2013, we sold all of our operations in Alabama, including our interests in 596 operated natural gas wells and all of our inventory and equipment.   We received approximately $60.0 million in net cash proceeds from the buyer, subject to additional post-closing working capital and other customary adjustments. Of this amount, approximately $1.2 million is being held in escrow for a period of 24 months pending certain closing conditions, and $50.0 million was used to reduce our outstanding debt under our reserve-based credit facility. In July 2013, we paid the purchaser $1.1 million, based on post-closing adjustments.
	During the nine months ended September 30, 2013, our discontinued operations had a net loss of $2.7 million consisting of revenues of $2.3 million, offset by expenses of $1.9 million and a loss on sale of $3.1 million. During the nine months ended September 30, 2012, our discontinued operations had a net loss of $3.0 million consisting of revenues of $9.0 million offset by expenses of $12.0 million. During the three months ended September 30, 2012, our discontinued operations had a net loss of $0.9 million consisting of revenues of $3.2 million offset by expenses of $4.1 million. At December 31, 2012, our discontinued operations had current assets of $1.9 million, long-term assets of $67.4 million, current liabilities of $1.6 million and long-term liabilities of $7.7 million. The current assets primarily represented accounts receivable for natural gas sales and the current liabilities primarily represented accounts payable and accrued liabilities. Long-term assets represented natural gas properties, equipment and facilities and the long-term liabilities represented asset retirement obligations.

Subsequent_Events

Subsequent Events	9 Months Ended
	Sep. 30, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	15. SUBSEQUENT EVENTS
	We evaluated subsequent events through the time of filing this Quarterly Report on Form 10-Q.  No subsequent events occurred subsequent to the balance sheet or prior to the filing of this report that would have a material impact on our consolidated financial statements or results of operations.

Organization_And_Basis_Of_Pres1

Organization And Basis Of Presentation (Policies)	9 Months Ended
	Sep. 30, 2013
Organization And Basis Of Presentation [Abstract]	'
Basis Of Presentation	'
	Basis of Presentation
	These unaudited condensed consolidated financial statements include the accounts of CEP 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 CEP and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2012, which was filed with the SEC on March 11, 2013, and amended by Amendment No. 1 thereto filed with the SEC on April 18, 2013.
Use Of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes.  These estimates and the underlying assumptions affect the amounts of assets and liabilities reported disclosures about contingent assets and liabilities and reported amounts of revenues and expenses.  The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (NGLs); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities.  As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use.  These estimates and assumptions are based on management’s best estimates and judgment.  Management evaluates its estimates and assumptions on an ongoing 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.
Reclassification	'
	Reclassifications
	Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation.  These reclassifications had no impact on the previously reported net income (loss) for any periods.

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Earnings per Unit	'
	Earnings per Unit
	Basic earnings per unit (EPU) are computed by dividing net income attributable to unitholders by the weighted average number of units outstanding during each period. At September 30, 2013, we had 1,615,017 Class A units and 28,463,746 Class B common units outstanding. Of the Class B common units, 386,579 units are restricted unvested common units granted and outstanding.
	The following table presents earnings per common unit amounts (in thousands, except per unit data):
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Numerator:
	Loss from continuing operations allocable to unitholders	$	-3,257	$	-10,269	$	-12,791	$	-7,262
	Loss from discontinued operations allocable to unitholders		—		-894		-2,686		-3,026
	Loss allocable to unitholders	$	-3,257	$	-11,163	$	-15,477	$	-10,288
	Denominator:
	Weighted average units outstanding		26,888,303		24,169,012		24,840,502		24,171,669
	Net earnings per unit:
	Basic:
	Loss from continuing operations allocable to unitholders	$	-0.12	$	-0.42	$	-0.51	$	-0.3
	Loss from discontinued operations allocable to unitholders		—		-0.04		-0.11		-0.13
	Loss allocable to unitholders	$	-0.12	$	-0.46	$	-0.62	$	-0.43
	Diluted:
	Loss from continuing operations allocable to unitholders	$	-0.12	$	-0.42	$	-0.51	$	-0.3
	Loss from discontinued operations allocable to unitholders		—		-0.04		-0.11		-0.13
	Loss allocable to unitholders	$	-0.12	$	-0.46	$	-0.62	$	-0.43
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, 2013, and our checks-in-transit reported in accounts payable were $0.5 million at December 31, 2012.
	We have established an escrow account for $0.6 million related to a vendor dispute, which is included in other non-current assets in our consolidated balance sheets at September 30, 2013, and December 31, 2012. This amount will remain in the escrow account until the dispute has been resolved.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Earnings Per Common Unit Amounts	'
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
	Numerator:
	Loss from continuing operations allocable to unitholders	$	-3,257	$	-10,269	$	-12,791	$	-7,262
	Loss from discontinued operations allocable to unitholders		—		-894		-2,686		-3,026
	Loss allocable to unitholders	$	-3,257	$	-11,163	$	-15,477	$	-10,288
	Denominator:
	Weighted average units outstanding		26,888,303		24,169,012		24,840,502		24,171,669
	Net earnings per unit:
	Basic:
	Loss from continuing operations allocable to unitholders	$	-0.12	$	-0.42	$	-0.51	$	-0.3
	Loss from discontinued operations allocable to unitholders		—		-0.04		-0.11		-0.13
	Loss allocable to unitholders	$	-0.12	$	-0.46	$	-0.62	$	-0.43
	Diluted:
	Loss from continuing operations allocable to unitholders	$	-0.12	$	-0.42	$	-0.51	$	-0.3
	Loss from discontinued operations allocable to unitholders		—		-0.04		-0.11		-0.13
	Loss allocable to unitholders	$	-0.12	$	-0.46	$	-0.62	$	-0.43

Acquisition_And_Divestiture_Ta

Acquisition And Divestiture (Tables)	9 Months Ended
	Sep. 30, 2013
Acquisition And Divestiture [Abstract]	'
Estimated Values Of Assets Acquired	'
			1-Aug-13
	Oil and natural gas properties, equipment and facilities		$	30,409
	Asset retirement obligation			-1,088
	Net assets acquired		$	29,321
Revenues And Lease Operating Expenses	'
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
		2013			2012		2013		2012
	Revenue	$	3,936		$	4,516	$	12,764	$	15,904
	Lease Operating Expenses	$	797		$	1,184	$	3,018	$	3,795
Supplemental Pro Forma Information	'
		Pro Forma					Pro Forma
		Three Months Ended					Nine Months Ended
		September 30,					September 30,
	(In thousands)	2013			2012		2013		2012
	Revenue	$	16,067		$	7,793	$	45,383	$	48,994
	Net Loss	$	-1,433		$	-8,370	$	-8,569	$	-186
	Basic loss per unit	$	-0.05		$	-0.28	$	-0.29	$	-0.01
	Diluted loss per unit	$	-0.05		$	-0.28	$	-0.29	$	-0.01

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2013
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, 2013 (in thousands):
		Fair Value Measurements at September 30, 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		30-Sep-13
	Risk Mgmt Assets	$	—	$	18,225	$	—	$	-1,625	$	16,600
	Risk Mgmt Liabilities		—		-1,625		—		1,625		—
	Total Net Assets and Liabilities	$	—	$	16,600	$	—	$	—	$	16,600
	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, 2012 (in thousands):
		Fair Value Measurements at December 31, 2012
		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-12
	Risk Mgmt Assets	$	—	$	31,030	$	—	$	-5,634	$	25,396
	Risk Mgmt Liabilities		—		-6,794		—		5,634		-1,160
	Total Net Assets and Liabilities	$	—	$	24,236	$	—	$	—	$	24,236

Derivative_And_Financial_Instr1

Derivative And Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2013
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
	2013													1,691,540	$	6.18	1,691,540	$	6.18
	2014	1,575,000		$	5.75		1,592,500		$	5.75	1,610,000	$	5.75	1,610,000	$	5.75	6,387,500	$	5.75
	2015	1,011,055		$	4.27		971,604		$	4.27	938,968	$	4.27	908,492	$	4.27	3,830,119	$	4.27
	2016	441,492		$	4.31		426,825		$	4.31	414,329	$	4.31	403,684	$	4.31	1,686,330	$	4.31
																	13,595,489
	MTM Fixed Price Basis Swaps– CenterPoint Energy Gas Transmission (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 $
	2013													1,223,985	$	0.39	1,223,985	$	0.39
	2014	1,178,422		$	0.39		1,133,022		$	0.39	1,084,270	$	0.39	1,047,963	$	0.39	4,443,677	$	0.39
																	5,667,662
	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
	2013													65,256	$	99.93	65,256	$	99.93
	2014	60,928		$	94.64		57,154		$	94.67	53,797	$	94.72	50,597	$	94.80	222,476	$	94.70
	2015	47,747		$	90.95		45,065		$	91.00	42,672	$	91.04	40,329	$	91.10	175,813	$	91.02
	2016	17,957		$	85.50		16,985		$	85.50	16,048	$	85.50	15,127	$	85.50	66,117	$	85.50
																	529,662
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-13			31-Dec-12
	Commodity – MTM		Risk management assets - current		$	13,581		$	19,005
	Commodity – MTM		Risk management assets  - non-current			4,644			12,025
			Total gross assets			18,225			31,030
	Commodity – MTM		Risk management assets – current			-1,385			-1,040
	Commodity – MTM		Risk management assets – non-current			-240			-946
	Commodity – MTM		Rick management liabilities – current			—			-523
	Commodity – MTM		Risk management liabilities – non-current			—			-637
	Interest Rate - MTM		Risk management assets – non-current			—			-3,648
			Total gross liabilities			-1,625			-6,794
			Total net assets and liabilities		$	16,600		$	24,236
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		2013			2012
	Commodity – MTM – Unrealized		Natural gas sales		$	-2,995		$	-8,746
	Commodity – MTM – Unrealized		Oil and liquids sales			-1,350			-1,412
	Commodity – MTM – Realized		Natural gas sales			4,174			5,934
	Commodity – MTM – Realized		Oil and liquids sales			-235			302
	Interest Rate – MTM – Unrealized		Interest expense			—			92
	Interest Rate – MTM - Realized		Interest expense			—			-460
			Total		$	-406		$	-4,290
					Amount of Gain/(Loss) in Income
			Location of Gain/(Loss)		For the Nine Months Ended September 30,
	Derivative Type		in Income		2013			2012
	Commodity – MTM – Unrealized		Natural gas sales		$	-10,124		$	-9,329
	Commodity – MTM – Unrealized		Oil and liquids sales			-1,160			876
	Commodity – MTM – Realized		Natural gas sales			11,448			19,200
	Commodity – MTM – Realized		Oil and liquids sales			272			426
	Interest Rate – MTM – Unrealized		Interest expense			3,648			697
	Interest Rate – MTM - Realized		Interest expense			-3,713			-1,746
			Total		$	371		$	10,124
					Amount of Gain/(Loss) Reclassified from
			Location of Gain/(Loss) for		AOCI into Income – Effective
			Effective and Ineffective		For the Three Months Ended September 30,
	Derivative Type		Portion of Derivative in Income		2013			2012
	Commodity – Cash Flow		Natural gas sales		$	—		$	1,722
			Total		$	—		$	1,722
					Amount of Gain/(Loss) Reclassified from
			Location of Gain/(Loss) for		AOCI into Income – Effective
			Effective and Ineffective		For the Nine Months Ended September 30,
	Derivative Type		Portion of Derivative in Income		2013			2012
	Commodity – Cash Flow		Natural gas sales		$	—		$	4,367
			Total		$	—		$	4,367

Oil_And_Natural_Gas_Properties1

Oil And Natural Gas Properties (Tables)	9 Months Ended
	Sep. 30, 2013
Oil And Natural Gas Properties [Abstract]	'
Oil and Natural Gas Properties	'
		September 30, 2013		December 31, 2012
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	635,993	$	591,889
	Unproved property		1,487		1,380
	Total property costs		637,480		593,269
	Materials and supplies		846		771
	Land		751		751
	Total		639,077		594,791
	Less: Accumulated depreciation, depletion, amortization and
	impairments		-489,083		-474,669
	Oil and natural gas properties and equipment, net	$	149,994	$	120,122
Depletion, Depreciation, Amortization and Impairments	'
		Nine Months Ended September 30,
		2013		2012
	DD&A of oil and natural gas-related assets	$	15,056	$	7,078
	Asset Impairments		—		107
	Total	$	15,056	$	7,185

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2013
Asset Retirement Obligation [Abstract]	'
Reconciliation of Asset Retirement Obligation	'
		September 30,		December 31,
		2013		2012
	Asset retirement obligation, beginning balance	$	7,665	$	7,052
	Liabilities incurred		1,254		162
	Liabilities settled		-3		-8
	Accretion expense		409		459
	Asset retirement obligation, ending balance	$	9,325	$	7,665

Recovered_Sheet1

Organization and Basis of Presentation (Details)	0 Months Ended	9 Months Ended
	Aug. 09, 2013	Sep. 30, 2013
Organization [Line Items]	'	'
Number of business segments	'	1
Constellation Energy Partners Management [Member] | Common Class A	'	'
Organization [Line Items]	'	'
Units owned by third party	'	484,505
Constellation Energy Partners Management [Member] | Common Class B	'	'
Organization [Line Items]	'	'
Units owned by third party	'	5,918,894
Sanchez Energy Partners I [Member] | Common Class A	'	'
Organization [Line Items]	'	'
Units owned by third party	1,130,512	1,130,512
Units owned by third party, percentage of total shares	70.00%	70.00%
Sanchez Energy Partners I [Member] | Common Class B	'	'
Organization [Line Items]	'	'
Units owned by third party	4,724,407	4,724,407
Units owned by third party, percentage of total shares	16.60%	'

Recovered_Sheet2

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)	9 Months Ended
In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012
			Common Class A	Common Class A	Common Class A	Common Class B	Common Class B	Common Class B
Class of Stock [Line Items]	'	'	'	'	'	'	'	'
Common units outstanding	'	'	1,615,017	483,418	483,304	28,463,746	23,687,507	23,681,878
Restricted unvested common units granted and outstanding	'	'	'	'	'	386,579	'	'
Checks-in-transit reported in accounts payable	$0	$0.50	'	'	'	'	'	'
Escrow account related to vendor dispute	0.6	0.6	'	'	'	'	'	'
Escrow account	$1.20	'	'	'	'	'	'	'
Period for funds held in escrow	'24 months	'	'	'	'	'	'	'

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Earnings Per Common Unit Amounts) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Summary Of Significant Accounting Policies [Abstract]	'	'	'	'
Loss from continuing operations allocable to unitholders	($3,257)	($10,269)	($12,791)	($7,262)
Loss from discontinued operations allocable to unitholders	'	-894	-2,686	-3,026
Net loss	($3,257)	($11,163)	($15,477)	($10,288)
Weighted average units outstanding	26,888,303	24,169,012	24,840,502	24,171,669
Loss from continuing operations allocable to unitholders	($0.12)	($0.42)	($0.51)	($0.30)
Loss from discontinued operation allocable to unitholders	'	($0.04)	($0.11)	($0.13)
Net loss per unit-Basic	($0.12)	($0.46)	($0.62)	($0.43)
Loss from continuing operations allocable to unitholders	($0.12)	($0.42)	($0.51)	($0.30)
Loss from discontinued operations allocable to unitholders	'	($0.04)	($0.11)	($0.13)
Net loss per unit-Diluted	($0.12)	($0.46)	($0.62)	($0.43)

Acquisition_And_Divestitures_N

Acquisition And Divestitures (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended	9 Months Ended		0 Months Ended			9 Months Ended	0 Months Ended	9 Months Ended
In Millions, except Share data, unless otherwise specified	Feb. 28, 2013	Mar. 31, 2013	Sep. 30, 2013	Aug. 09, 2013	Aug. 09, 2013	Aug. 09, 2013	Aug. 09, 2013	Sep. 30, 2013	Aug. 09, 2013	Sep. 30, 2013
				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]
							Common Class A	Common Class A	Common Class B	Common Class B
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'	'	'
Proceeds from sale of business	$63	'	'	'	'	'	'	'	'	'
Gain (Loss) on sale of business	'	-3.1	-3.1	'	'	'	'	'	'	'
Purchase price for acquisition	'	'	'	'	'	30.4	'	'	'	'
Cash paid to SEP I	'	'	'	'	'	20.1	'	'	'	'
Units owned by third party	'	'	'	'	'	'	1,130,512	1,130,512	4,724,407	4,724,407
Units owned by third party, percentage of total shares	'	'	'	'	'	'	70.00%	70.00%	16.60%	'
Amount borrowed from reserve based credit facility	'	'	'	'	$16.70	'	'	'	'	'
Number of wells acquired	'	'	'	67	'	'	'	'	'	'

Acquisition_And_Divestiture_Es

Acquisition And Divestiture (Estimated Values Of Assets Acquired) (Details) (USD $)	Sep. 30, 2013	Aug. 01, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Acquisition And Divestiture [Abstract]	'	'	'
Oil and natural gas properties, equipment and facilities	$638,231	$30,409	$594,020
Asset retirement obligation	-9,325	-1,088	-7,665
Net assets acquired	'	$29,321	'

Acquisition_And_Divestiture_Re

Acquisition And Divestiture (Revenues And Lease Operating Expenses) (Details) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Business Acquisition [Line Items]	'	'	'	'
Revenues	$12,131	$3,277	$32,619	$33,090
Lease Operating Expenses	5,191	4,869	13,332	14,727
Sanchez Oil And Gas Properties [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenues	3,936	4,516	12,764	15,904
Lease Operating Expenses	$797	$1,184	$3,018	$3,795

Acquisition_And_Divestiture_Su

Acquisition And Divestiture (Supplemental Pro Forma Information) (Details) (Sanchez Oil And Gas Properties [Member], USD $)	3 Months Ended		9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Sanchez Oil And Gas Properties [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenue	$16,067	$7,793	$45,383	$48,994
Net Loss	($1,433)	($8,370)	($8,569)	($186)
Basic loss per unit	($0.05)	($0.28)	($0.29)	($0.01)
Diluted loss per unit	($0.05)	($0.28)	($0.29)	($0.01)

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	$16,600	$25,396
Risk Mgmt Liabilities	'	-1,160
Total Net Assets and Liabilities	16,600	24,236
Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	18,225	31,030
Risk Mgmt Liabilities	-1,625	-6,794
Total Net Assets and Liabilities	16,600	24,236
Netting Cash And Collateral [Member]	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	-1,625	-5,634
Risk Mgmt Liabilities	$1,625	$5,634

Derivative_And_Financial_Instr2

Derivative And Financial Instruments (Narrative) (Details) (USD $)	1 Months Ended	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2013	Mar. 31, 2013	Sep. 30, 2013
	bbl	MMBTU	item
Derivative [Line Items]	'	'	'
Number of counterparties	'	'	2
Impact of non-performance credit risk	'	'	$0.20
Decrease in non-cash mark-to-market gain	'	'	0.1
Reduction in accumulated other comprehensive income	'	'	0.1
Percentage of hedge of anticipated production volume, 2015	'	'	100.00%
Estimated projected natural gas production	'	'	3
Cost to liquidate derivative hedge	'	0.3	'
Amount reduced from outstanding swap positions	'	1,041,814	'
Derivative contract swap, fixed price	3.66	3.66	'
Reduction in outstanding interest rate swaps	30	30	'
Increase in interest rate swap settlement	2.1	'	'
Number of barrels of oil	58,157	'	'
Execution of amendment	$0.20	'	'
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]	'	'	'
Stated swap price	98.1	98.1	'
2015 Oil Trade [Member]	'	'	'
Derivative [Line Items]	'	'	'
Stated swap price	93.5	93.5	'

Derivative_And_Financial_Instr3

Derivative And Financial Instruments (Summary Of Hedges In Place) (Details)	9 Months Ended
	Sep. 30, 2013
	MMBTU
NYMEX 2013 [Member]	'
Volume	1,691,540
Average Price	6.18
NYMEX 2014 [Member]	'
Volume	6,387,500
Average Price	5.75
NYMEX 2015 [Member]	'
Volume	3,830,119
Average Price	4.27
NYMEX 2016 [Member]	'
Volume	1,686,330
Average Price	4.31
NYMEX [Member]	'
Volume	13,595,489
Centerpoint, ONEOK, Or Southern Star 2013 [Member]	'
Volume	1,223,985
Average Price	0.39
Centerpoint, ONEOK, Or Southern Star 2014 [Member]	'
Volume	4,443,677
Average Price	0.39
Centerpoint, ONEOK, Or Southern Star [Member]	'
Volume	5,667,662
West Texas Intermediate 2013 [Member]	'
Volume	65,256
Average Price	99.93
West Texas Intermediate 2014 [Member]	'
Volume	222,476
Average Price	94.7
West Texas Intermediate 2015 [Member]	'
Volume	175,813
Average Price	91.02
West Texas Intermediate 2016 [Member]	'
Volume	66,117
Average Price	85.5
West Texas Intermediate [Member]	'
Volume	529,662
First Quarter [Member] | NYMEX 2014 [Member]	'
Volume	1,575,000
Average Price	5.75
First Quarter [Member] | NYMEX 2015 [Member]	'
Volume	1,011,055
Average Price	4.27
First Quarter [Member] | NYMEX 2016 [Member]	'
Volume	441,492
Average Price	4.31
First Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member]	'
Volume	1,178,422
Average Price	0.39
First Quarter [Member] | West Texas Intermediate 2014 [Member]	'
Volume	60,928
Average Price	94.64
First Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Volume	47,747
Average Price	90.95
First Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Volume	17,957
Average Price	85.5
Second Quarter [Member] | NYMEX 2014 [Member]	'
Volume	1,592,500
Average Price	5.75
Second Quarter [Member] | NYMEX 2015 [Member]	'
Volume	971,604
Average Price	4.27
Second Quarter [Member] | NYMEX 2016 [Member]	'
Volume	426,825
Average Price	4.31
Second Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member]	'
Volume	1,133,022
Average Price	0.39
Second Quarter [Member] | West Texas Intermediate 2014 [Member]	'
Volume	57,154
Average Price	94.67
Second Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Volume	45,065
Average Price	91
Second Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Volume	16,985
Average Price	85.5
Third Quarter [Member] | NYMEX 2014 [Member]	'
Volume	1,610,000
Average Price	5.75
Third Quarter [Member] | NYMEX 2015 [Member]	'
Volume	938,968
Average Price	4.27
Third Quarter [Member] | NYMEX 2016 [Member]	'
Volume	414,329
Average Price	4.31
Third Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member]	'
Volume	1,084,270
Average Price	0.39
Third Quarter [Member] | West Texas Intermediate 2014 [Member]	'
Volume	53,797
Average Price	94.72
Third Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Volume	42,672
Average Price	91.04
Third Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Volume	16,048
Average Price	85.5
Fourth Quarter [Member] | NYMEX 2013 [Member]	'
Volume	1,691,540
Average Price	6.18
Fourth Quarter [Member] | NYMEX 2014 [Member]	'
Volume	1,610,000
Average Price	5.75
Fourth Quarter [Member] | NYMEX 2015 [Member]	'
Volume	908,492
Average Price	4.27
Fourth Quarter [Member] | NYMEX 2016 [Member]	'
Volume	403,684
Average Price	4.31
Fourth Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2013 [Member]	'
Volume	1,223,985
Average Price	0.39
Fourth Quarter [Member] | Centerpoint, ONEOK, Or Southern Star 2014 [Member]	'
Volume	1,047,963
Average Price	0.39
Fourth Quarter [Member] | West Texas Intermediate 2013 [Member]	'
Volume	65,256
Average Price	99.93
Fourth Quarter [Member] | West Texas Intermediate 2014 [Member]	'
Volume	50,597
Average Price	94.8
Fourth Quarter [Member] | West Texas Intermediate 2015 [Member]	'
Volume	40,329
Average Price	91.1
Fourth Quarter [Member] | West Texas Intermediate 2016 [Member]	'
Volume	15,127
Average Price	85.5

Derivative_And_Financial_Instr4

Derivative And Financial Instruments (Fair Value for Risk Management Assets and Liabilities) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-current	$12,196	$17,965
Risk management assets-non-current	4,404	7,431
Total gross assets	18,225	31,030
Risk management liabilities-current	'	-523
Risk management liabilities-non-current	'	-637
Total gross liabilities	-1,625	-6,794
Total net assets and liabilities	16,600	24,236
Risk Management Commodity [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-current	13,581	19,005
Risk management assets-non-current	4,644	12,025
Risk management liabilities-current	'	-523
Risk management liabilities-non-current	'	-637
Current Assets [Member] | Risk Management Commodity [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management liabilities-current	-1,385	-1,040
Noncurrent Assets [Member] | Risk Management Commodity [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management liabilities-non-current	-240	-946
Noncurrent Assets [Member] | Risk Management Interest Rate [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management liabilities-non-current	'	($3,648)

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, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	($406)	($4,290)	$371	$10,124
Natural Gas Sales [Member] | Unrealized Commodity [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	-2,995	-8,746	-10,124	-9,329
Natural Gas Sales [Member] | Realized Commodity [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	4,174	5,934	11,448	19,200
Oil And Liquids Sales [Member] | Unrealized Commodity [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	-1,350	-1,412	-1,160	876
Oil And Liquids Sales [Member] | Realized Commodity [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	-235	302	272	426
Interest Expense [Member] | Unrealized Interest Rate [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	'	92	3,648	697
Interest Expense [Member] | Realized Interest Rate [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Derivative gains (losses) recognized in income	'	($460)	($3,713)	($1,746)

Derivative_And_Financial_Instr6

Derivative And Financial Instruments (Fair Value Disclosures Applicable to Income Statement Reclassified) (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'	'	'
Amount of gain/ (loss) Reclassified from AOCI Income	'$-	'$1,722	'$-	'$4,367
Commodity - Cash Flow [Member] | Natural Gas Sales [Member]	'	'	'	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'	'	'
Amount of gain/ (loss) Reclassified from AOCI Income	'$-	'$1,722	'$-	'$4,367

Recovered_Sheet3

Oil and Natural Gas Properties (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended	9 Months Ended		1 Months Ended	0 Months Ended
	Feb. 28, 2013	Mar. 31, 2013	Sep. 30, 2013	Sep. 30, 2012	Mar. 31, 2012	Feb. 28, 2013	Jul. 31, 2013
				item	Woodford Shale	Robinson's Bend Field [Member]	Robinson's Bend Field [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'	'	'	'	'
Asset impairments	'	'	'	$107,000	'	'	'
Non-cash impairment charges	'	'	'	'	100,000	'	'
Cash flow estimates of discount rate	'	'	'	'	10.00%	'	'
Capitalized cost subject to impairment	'	'	'	'	3,600,000	'	'
Proceeds from sale of business	63,000,000	'	'	'	'	63,000,000	'
Gain (Loss) on sale	'	-3,100,000	-3,100,000	'	'	-3,100,000	'
Amount paid to purchased based on final settlement statement	'	'	'	'	'	1,200,000	1,100,000
Proceeds from sale of assets	'	'	100,000	'	'	'	'
Number of gross non-operated oil wells sold	'	'	'	14	'	'	'
Proceed from sale of interest of non-operated oil wells	'	'	'	$1,400,000	'	'	'

Recovered_Sheet4

Oil and Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil And Natural Gas Properties [Abstract]	'	'
Proved property	$635,993	$591,889
Unproved property	1,487	1,380
Total property costs	637,480	593,269
Materials and supplies	846	771
Land	751	751
Total	639,077	594,791
Less: Accumulated depreciation, depletion, amortization and impairments	-489,083	-474,669
Oil and natural gas properties and equipment, net	$149,994	$120,122

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, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Oil And Natural Gas Properties [Abstract]	'	'	'	'
DD&A of oil and natural gas-related assets	$5,491	$2,373	$15,056	$7,078
Asset Impairments	'	'	'	107
Total	'	'	$15,056	$7,185

Debt_Details

Debt (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012
Line of Credit Facility [Line Items]	'	'	'
Commitment fee on unutilized borrowing base	0.50%	'	'
Amortization of Debt Issuance Costs	$700,000	'	'
Unamortized debt issue costs	900,000	'	'
Outstanding debt under reserve-based credit facility	50,700,000	34,000,000	88,400,000
Remaining borrowing capacity	4,300,000	'	'
Societe Generale [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Reserve based credit facility maximum borrowing capacity	350,000,000	'	'
Borrowing base amount	55,000,000	'	'
Maturity date of reserve-based credit facility	30-May-17	'	'
Outstanding debt on our reserve based credit facility	$50,700,000	'	'
Commitment fee percentage	36.36%	'	'
OneWest Bank [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Commitment fee percentage	36.36%	'	'
Bank of Oklahoma [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
Commitment fee percentage	27.28%	'	'
Minimum | London Interbank Offered Rate (LIBOR) [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
LIBOR limit	2.50%	'	'
Minimum | ABR [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
LIBOR limit	1.50%	'	'
Maximum | London Interbank Offered Rate (LIBOR) [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
LIBOR limit	3.50%	'	'
Maximum | ABR [Member]	'	'	'
Line of Credit Facility [Line Items]	'	'	'
LIBOR limit	2.50%	'	'

Asset_Retirement_Obligation_Na

Asset Retirement Obligation (Narrative) (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
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, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Asset Retirement Obligation [Abstract]	'	'	'	'	'
Asset retirement obligation, beginning balance	'	'	$7,665	$7,052	$7,052
Liabilities incurred	'	'	1,254	'	162
Liabilities settled	'	'	-3	'	-8
Accretion expense	163	116	409	345	459
Asset retirement obligation, ending balance	$9,325	'	$9,325	'	$7,665

Related_Party_Transactions_Det

Related Party Transactions (Details)	0 Months Ended	9 Months Ended
	Aug. 09, 2013	Sep. 30, 2013
Related Party Transaction [Line Items]	'	'
Incentive interest received as percentage of quarterly distributions	'	15.00%
Constellation Energy Partners Management [Member] | Common Class A	'	'
Related Party Transaction [Line Items]	'	'
Units owned by third party	'	484,505
Constellation Energy Partners Management [Member] | Common Class B	'	'
Related Party Transaction [Line Items]	'	'
Units owned by third party	'	5,918,894
Sanchez Energy Partners I [Member] | Common Class A	'	'
Related Party Transaction [Line Items]	'	'
Units owned by third party	1,130,512	1,130,512
Units owned by third party, percentage of total shares	70.00%	70.00%
Sanchez Energy Partners I [Member] | Common Class B	'	'
Related Party Transaction [Line Items]	'	'
Units owned by third party	4,724,407	4,724,407
Units owned by third party, percentage of total shares	16.60%	'

Compensation_Details

Compensation (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'
Non-cash compensation expense	$0.80	$1.20
Unrecognized portion of share based compensation expense	0.6	'
Severance costs	1	'
General and Administrative Expense [Member]	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]	'	'
Non-cash compensation expense	0.2	'
Cash compensation expense	$0.80	'

Members_Equity_Details

Members' Equity (Details) (USD $)

9 Months Ended

In Thousands, except Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Long Term Incentive Plan

Long Term Incentive Plan

2009 Omnibus Incentive Compensation Plan

2009 Omnibus Incentive Compensation Plan

Common Class A

Common Class A

Common Class A

Common Class B

Common Class B

Common Class B

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

'

'

'

'

'

'

'

'

'

'

'

'

Shares units outstanding

'

'

'

'

'

'

1,615,017

483,418

483,304

28,463,746

23,687,507

23,681,878

Unvested restricted common stock issued

'

'

43,776

94,914

342,803

665,840

'

'

'

'

'

'

Common units granted

'

'

346,734

336,599

1,368,227

1,320,901

'

'

'

'

'

'

Common units available under incentive plan

'

'

450,000

450,000

1,650,000

1,650,000

'

'

'

'

'

'

Common units vested

'

'

302,958

241,685

1,025,424

655,061

'

'

'

'

'

'

Additional units granted

'

'

'

76,046

'

323,194

'

'

'

'

'

'

Common units tendered for tax withholding purpose

139,810

89,271

'

'

'

'

'

'

'

'

'

'

Units tendered by employees for tax withholding, cost

$185

$200

'

'

'

'

'

'

'

'

'

'

Discontinued_Operations_Detail

Discontinued Operations (Details) (USD $)	0 Months Ended	3 Months Ended		9 Months Ended				0 Months Ended
	Feb. 28, 2013	Mar. 31, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Aug. 09, 2013	Dec. 31, 2012	Feb. 28, 2013	Jul. 31, 2013	Jan. 31, 2013
						item		Robinson's Bend Field [Member]	Robinson's Bend Field [Member]	Robinson's Bend Field [Member]
								item		entity
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'	'	'	'
Number of entities sold	'	'	'	'	'	'	'	'	'	2
Proceeds from sale of business	$63,000,000	'	'	'	'	'	'	$63,000,000	'	'
Net cash proceeds from sale of business	'	'	'	'	'	'	'	60,000,000	'	'
Number of operated natural gas wells	'	'	'	'	'	67	'	596	'	'
Amount held in escrow	'	'	'	'	'	'	'	1,200,000	1,100,000	'
Escrow period	'	'	'	'	'	'	'	'24 months	'	'
Amount held in escrow used to reduce the debt under reserve based credit facility	'	'	'	'	'	'	'	50,000,000	'	'
Discontinued operations net loss	'	'	-894,000	-2,686,000	-3,026,000	'	'	'	'	'
Discontinued operations, revenues	'	'	3,200,000	2,300,000	9,000,000	'	'	'	'	'
Discontinued operations, expenses	'	'	4,100,000	1,900,000	12,000,000	'	'	'	'	'
Gain (Loss) on sale	'	-3,100,000	'	-3,100,000	'	'	'	-3,100,000	'	'
Discontinued operations, Current Assets	'	'	'	'	'	'	1,886,000	'	'	'
Discontinued operations, Long-term assets	'	'	'	'	'	'	67,373,000	'	'	'
Discontinued operations, Current Liabilities	'	'	'	'	'	'	1,578,000	'	'	'
Discontinued operations, Long term liabilities	'	'	'	'	'	'	$7,692,000	'	'	'