Evolve Transition Infrastructure (SNMP) 10-K27 Mar 142013 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
Document and Entity Information (USD $)	Dec. 31, 2013	Mar. 21, 2014	Jun. 28, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
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	'	28,399,502	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'
Entity Public Float	'	'	$33,467,455

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations And Comprehensive Loss (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Revenues	'	'
Natural gas sales	$23,129	$34,019
Oil and liquids sales	20,948	12,508
Total revenues	44,077	46,527
Operating expenses:	'	'
Lease operating expenses	18,858	19,411
Cost of sales	1,455	1,299
Production taxes	2,601	1,646
General and administrative	22,214	15,747
Loss on sale of assets	4	7
Depreciation, depletion, and amortization	18,972	11,732
Asset impairments (See Note 7)	2,357	109
Accretion expense	519	459
Total operating expenses	66,980	50,410
Other expense / (income)	'	'
Interest expense	3,150	5,734
Other income	-196	-155
Total other expenses	2,954	5,579
Total expenses	69,934	55,989
Loss from continuing operations	-25,857	-9,462
Loss from discontinued operations	-2,686	-77,081
Net loss	-28,543	-86,543
Change in fair value of commodity hedges	'	202
Cash settlement of commodity hedges	'	-5,639
Other comprehensive loss	'	-5,437
Comprehensive income (loss)	-28,543	-91,980
Loss per unit (See Note 1)	'	'
Weighted Average Units Outstanding - Basic and diluted	26,143,719	24,171,510
Distributions declared and paid per unit	'	'
Common Class A [Member]	'	'
Other expense / (income)	'	'
Loss from continuing operations	-517	-189
Loss from discontinued operations	-54	-1,542
Net loss	-571	-1,731
Loss per unit (See Note 1)	'	'
Loss from continuing operations per unit - Basic and diluted	($0.55)	($0.39)
Discontinued operations per unit - Basic and diluted	($0.06)	($3.19)
Net loss per unit - Basic and diluted	($0.61)	($3.58)
Weighted Average Units Outstanding - Basic and diluted	933,613	483,564
Common Class B [Member]	'	'
Other expense / (income)	'	'
Loss from continuing operations	-25,340	-9,273
Loss from discontinued operations	-2,632	-75,539
Net loss	($27,972)	($84,812)
Loss per unit (See Note 1)	'	'
Loss from continuing operations per unit - Basic and diluted	($1.01)	($0.39)
Discontinued operations per unit - Basic and diluted	($0.10)	($3.19)
Net loss per unit - Basic and diluted	($1.11)	($3.58)
Weighted Average Units Outstanding - Basic and diluted	25,210,106	23,687,946

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets	'	'
Cash and cash equivalents	$4,894	$1,959
Accounts receivable	6,678	5,615
Prepaid expenses	2,547	1,309
Risk management assets (See Note 5)	9,141	17,965
Current assets from discontinued operations	'	1,886
Total current assets	23,260	28,734
Oil and natural gas properties (See Note 7)	'	'
Oil and natural gas properties, equipment and facilities	639,156	594,020
Material and supplies	1,054	771
Less accumulated depreciation, depletion, amortization, and impairments	-495,215	-474,669
Net oil and natural gas properties	144,995	120,122
Other assets	'	'
Debt issue costs (net of accumulated amortization of $9,003 and $7,775, respectively)	824	1,168
Risk management assets (See Note 5)	1,461	7,431
Restricted cash	1,748	600
Other non-current assets	2,245	2,594
Long-term assets from discontinued operations	'	67,373
Total assets	174,533	228,022
Current liabilities	'	'
Accounts payable	12	480
Accrued liabilities	12,763	7,174
Royalty payable	1,242	1,418
Risk management liabilities (See Note 5)	'	523
Debt (See Note 6)	'	50,000
Current liabilities from discontinued operations	'	1,578
Total current liabilities	14,017	61,173
Other liabilities	'	'
Asset retirement obligation	9,513	7,665
Risk management liabilities (See Note 5)	'	637
Other non-current liabilities	1,398	589
Debt (See Note 6)	50,700	34,000
Other long-term liabilities from discontinued operations	'	7,692
Total other liabilities	61,611	50,583
Total liabilities	75,628	111,756
Commitments and contingencies (See Note 10)	'	'
Members' equity	'	'
Total members' equity	98,905	116,266
Total liabilities and members' equity	174,533	228,022
Common Class A [Member]	'	'
Members' equity	'	'
Limited partners' capital account	2,591	2,326
Common Class B [Member]	'	'
Members' equity	'	'
Limited partners' capital account	$96,314	$113,940

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Debt issue costs, accumulated amortization	$9,003	$7,775
Common Class A [Member]	'	'
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 [Member]	'	'
Share units authorized	28,848,785	24,124,378
Share units issued	28,462,185	23,687,507
Shares units outstanding	28,462,185	23,687,507

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities:	'	'
Net loss	($28,543)	($86,543)
Adjustments to reconcile net loss to cash provided by operating activities	'	'
Depreciation, depletion and amortization	18,972	11,732
Asset impairments (See Note 7)	2,357	109
Amortization of debt issuance costs	1,289	1,310
Accretion expense	519	459
Equity earnings in affiliate	-271	-173
Loss from disposition of property and equipment	4	7
Bad debt expense	44	35
Mark-to-market on derivatives:	'	'
Total gains	1,551	-14,640
Cash settlements	12,082	22,189
Unit-based compensation programs	1,049	1,497
Discontinued operations	2,686	77,081
Changes in Assets and Liabilities:	'	'
Increase in accounts receivable	-1,106	-924
Increase in prepaid expenses	-1,238	-144
Decrease in other assets	8	'
Decrease in accounts payable	-468	-370
Increase (decrease) in accrued liabilities	4,824	-2,446
Increase (decrease) in royalty payable	-176	115
Increase in other liabilities	559	493
Net cash provided by continuing operations	14,142	9,787
Net cash provided by discontinued operations	1,062	4,421
Net cash provided by operating activities	15,204	14,208
Cash flows from investing activities:	'	'
Cash paid for acquisitions, net of cash acquired	-20,221	-252
Development of natural gas properties	-15,694	-15,336
Proceeds from sale of property and equipment	58,987	1,508
Increase in cash held for escrow	-1,148	-600
Distributions from equity affiliate	245	230
Net cash provided by (used in) continuing operations	22,169	-14,450
Net cash used in discontinued operations	'	-302
Net cash (used in) investing activities	22,169	-14,752
Cash flows from financing activities:	'	'
Members' distributions	'	'
Proceeds from issuance of debt	16,894	'
Repayment of debt	-50,194	-14,400
Units tendered by employees for tax withholdings	-185	-200
Debt issue costs	-953	-55
Net cash used in continuing operations	-34,438	-14,655
Net cash used in financing activities	-34,438	-14,655
Net increase (decrease) in cash	2,935	-15,199
Cash and cash equivalents, beginning of period	1,959	17,158
Cash and cash equivalents, end of period	4,894	1,959
Supplemental disclosures of cash flow information:	'	'
Change in accrued capital expenditures	-1,674	307
Cash received during the period for interest	'	1
Cash paid during the period for interest	-1,881	-3,650
Cash paid during the period for income taxes	($75)	($19)

Consolidated_Statements_of_Cha

Consolidated Statements of Changes In Members' Equity (USD $)	Common Class A [Member]	Common Class B [Member]	Accumulated Other Comprehensive Income [Member]	Total
In Thousands, except Share data	Common Class A [Member]	Common Class B [Member]	Accumulated Other Comprehensive Income [Member]	Total
Beginning Balance at Dec. 31, 2011	$4,030	$197,453	$5,437	$206,920
Beginning Balance (in shares) at Dec. 31, 2011	485,033	23,766,632	'	'
Distributions	'	'	'	'
Units tendered by employees for tax (in shares)	-1,845	-90,425	'	'
Units tendered by employees for tax	-4	-196	'	-200
Change in fair value of commodity hedges	'	'	202	202
Cash settlement of commodity hedges	'	'	-5,639	-5,639
Unit-based compensation programs (in shares)	230	11,300	'	'
Unit-based compensation programs	31	1,495	'	1,526
Net loss	-1,731	-84,812	'	-86,543
Ending Balance at Dec. 31, 2012	2,326	113,940	'	116,266
Ending Balance (in shares) at Dec. 31, 2012	483,418	23,687,507	'	'
Distributions	'	'	'	'
Units tendered by employees for tax (in shares)	-2,853	-139,810	'	'
Units tendered by employees for tax	-4	-181	'	-185
Unit-based compensation programs (in shares)	3,940	190,081	'	'
Unit-based compensation programs	21	1,028	'	1,049
Unit issued for acquisition of properties (in shares)	1,130,512	4,724,407	'	'
Unit issued for acquisition of properties	818	9,500	'	10,318
Net loss	-570	-27,973	'	-28,543
Ending Balance at Dec. 31, 2013	$2,591	$96,314	'	$98,905
Ending Balance (in shares) at Dec. 31, 2013	1,615,017	28,462,185	'	'

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
Summary Of Significant Accounting Policies	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Summary Of Significant Accounting Policies	'
	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Organization and Basis of Presentation
	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 December 31, 2013, Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned 484,505, or 30%, 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), an affiliate 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.
	Accounting policies used by us conform to accounting principles generally accepted in the United States of America. The accompanying financial statements include the accounts of us 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.
	Use of Estimates
	Estimates and assumptions are made when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:
	•reported amounts of revenue and expenses in the Consolidated Statements of Operations and Other Comprehensive Loss during the reported periods,
	•reported amounts of assets and liabilities in the Consolidated Balance Sheets at the dates of the financial statements,

	•disclosure of quantities of reserves and use of those reserve quantities for depreciation, depletion and amortization, and
	•disclosure of contingent assets and liabilities at the date of the financial statements.
	These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control. As a result, changes in facts and circumstances or additional information may result in revised estimates or actual amounts may materially differ from these amounts.
	Reclassifications
	Certain reclassifications have been made to the prior periods to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.
	Discontinued Operations
	In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama. The related results of operations and cash flows have been classified as discontinued operations in the consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information. Unless otherwise indicated, information presented in the Notes to Consolidated Financial Statements relates only to the Company’s continuing operations. Information related to discontinued operations is included in Note 2. Discontinued Operations.
	Cash and Cash Equivalents
	All highly liquid investments with original maturities of three months or less are considered cash equivalents. Checks-in-transit were none in 2013 and $0.6 million in 2012 and are included in accounts payable in our consolidated balance sheets.
	Restricted Cash
	Restricted cash at December 31, 2013 of $1.7 million is held in escrow in relation to the sale of the Robinson’s Bend Field assets and related to litigation involving one of our service providers. Restricted cash at December 31, 2012 was comprised of $0.6 million held in escrow related to litigation involving one of our service providers.
	Concentration of Credit Risk and Accounts Receivable
	Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our reserve-based credit facility and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from purchasers of oil and natural gas. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was less than $0.1 million in each of 2012 and 2013. We have no off-balance-sheet credit exposure related to our operations or customers.

	For the year ended December 31, 2013, five customers accounted for approximately 22%, 20%, 17%, 14% and 8% of our sales revenues. For the year ended December 31, 2012, five customers accounted for approximately 28%, 10%, 9%, 9% and 8% of our sales revenues.
	Oil and Natural Gas Properties
	Oil and Natural Gas Properties
	We follow the successful efforts method of accounting for our oil and natural gas exploration, development and production activities. Leasehold acquisition costs, property acquisition and the costs of development of proved areas are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.
	Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place.
	Depreciation, Depletion and Amortization
	Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. It has been our historical practice to use our year-end reserve report to adjust our depreciation, depletion, and amortization expense for the fourth quarter. Depreciation, depletion, and amortization expense is calculated using year-end reserve reports based on the SEC-required price. As more fully described in Note 15, proved reserves estimates are subject to future revisions when additional information becomes available.
	Asset Retirement Obligation
	As described in Note 11, estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
	Unsuccessful Wells
	Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.
	Impairment
	Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Cash flow estimates for the impairment testing exclude derivative instruments. Refer to Note 7 for additional information.
	Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that we expect to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.
	Property acquisition costs are capitalized when incurred.
	Support Equipment and Facilities
	Support equipment and facilities consist of certain of our water treatment facilities, gathering lines, roads, pipelines and other various support equipment. Items are capitalized when acquired and depreciated using the straight-line method over the useful life of the assets.
	Materials and Supplies
	Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.
	Oil and Natural Gas Reserve Quantities
	Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2013 and 2012 is described in detail in Note 15.
	Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
	Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
	Derivatives and Hedging Activities
	We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure on our borrowings under our reserve-based credit facility.
	We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheet as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price or interest rate exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets under the captions “Risk management assets” and “Risk management liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations and comprehensive income (loss) under the caption “Oil and liquid sales” or “Natural gas sales” and settled interest rate swaps as “Interest expense.”
	Revenue Recognition
	Sales of oil and natural gas are recognized when oil or natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale are reasonably assured and the sales price is fixed or determinable. Oil and natural gas is sold on a monthly basis. Most of our sales contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil or natural gas, and prevailing supply and demand conditions, so that the price of the oil or natural gas fluctuates to remain competitive with other available energy supplies. As a result, revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our oil and natural gas contracts are customary in the industry.
	Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no gas imbalance positions at December 31, 2013 or 2012, respectively.
	Income Taxes
	CEP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of its members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. CEP is subject to franchise tax obligations in Kansas and Texas and state tax obligations in Alabama and Oklahoma. CEP also has informational filing requirements in Georgia, Indiana, Louisiana, Maine, Missouri, New Jersey, New York, Oregon, Pennsylvania, and West Virginia because we have resident unitholders in these states.
	Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2013, and 2012, the current federal and state tax liability for the entity was less than $0.1 million and $0.1 million, respectively. The entity has no deferred tax assets or liabilities. Taxes are paid to the IRS or the applicable states in quarterly installments.
	Earnings per Unit
	Basic earnings per unit (EPU) is computed by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period.
	As of December 31, 2013 and 2012, we had unvested restricted common units outstanding, which were considered dilutive securities. These units will be considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities.
	The following table presents our calculation of basic and diluted units outstanding for the periods indicated:





		Year Ended December 31,
		2013		2012
Weighted average units outstanding during period:
Class A units - Basic and Diluted			933,613		483,564
Class B Common units - Basic and Diluted			25,210,106		23,687,946
			26,143,719		24,171,510

At December 31, 2013, we had 380,327 Class B common units that were restricted unvested common units granted and outstanding. These units were excluded from the diluted weighted average common unit outstanding number.

The following table presents our basic and diluted income per unit for the year ended December 31, 2013 (in thousands, except for per unit amounts):




		Total		Class A Units		Class B Units

Loss from continuing operations		$	-25,857
Distributions			-	$	-	$	-
Assumed allocation of loss from continuing operations			-25,857		-517		-25,340
Discontinued operations			-2,686		-54		-2,632
Assumed net loss to be allocated		$	-28,543	$	-571	$	-27,972

Basic and diluted loss from continuing operations per unit				$	-0.55	$	-1.01
Basic and diluted loss from discontinued operations per unit				$	-0.06	$	-0.1
Basic and diluted loss per unit				$	-0.61	$	-1.11




The following table presents our basic and diluted income per unit for the year ended December 31, 2012 (in thousands, except for per unit amounts):




		Total		Class A Units		Class B Units

Loss from continuing operations		$	-9,462
Distributions			-	$	-	$	-
Assumed allocation of loss from continuing operations			-9,462		-189		-9,273
Discontinued operations			-77,081		-1,542		-75,539
Assumed net loss to be allocated		$	-86,543	$	-1,731	$	-84,812

Basic and diluted loss from continuing operations per unit				$	-0.39	$	-0.39
Basic and diluted loss from discontinued operations per unit				$	-3.19	$	-3.19
Basic and diluted loss per unit				$	-3.58	$	-3.58
Comprehensive Loss
Comprehensive loss includes net earnings (loss) as well as unrealized gains and losses on derivative instruments that were previously accounted for as cash flow hedges.

Environmental Cost
We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Federal Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.
Unit-Based Compensation
We record compensation expense for all equity grants issued under the Long-Term Incentive Program and the 2009 Omnibus Incentive Compensation Plan based on the fair value at the grant date, recognized over the vesting period.
Other Contingencies
We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.
Recent Pronouncements and Accounting Changes
From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (the FASB), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our consolidated financial statements upon adoption.
In December 2011, the FASB issued 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 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. In January 2013, the FASB issued ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, an amendment to ASC Topic 210. The update clarifies that the scope of ASU No. 2011-11, Disclosures about Offsetting Assets and Liabilities, applies to derivatives accounted for in accordance with ASC Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset or subject to an enforceable master netting arrangement or similar agreement. The guidance was effective beginning on or after January 1, 2013, and primarily impacts the disclosures associated with our commodity and interest rate derivatives. The adoption of this guidance did not have any impact on our consolidated financial position, results of operations or cash flows.

In June 2011, the FASB issued ASU 2011-05, Comprehensive Income (Topic 220) that requires entities to present net income and other comprehensive income in either a single continuous statement or in two separate, but consecutive, statements of net income and other comprehensive income. The option to present items of other comprehensive income in the statement of changes in equity is eliminated. The amended guidance did not have any material impact on our financial statements or our disclosures.

Discontinued_Operations

Discontinued Operations	12 Months Ended
Discontinued Operations	Dec. 31, 2013
Discontinued Operations [Abstract]	'
Discontinued Operations	'
	2. DISCONTINUED OPERATIONS
	Sale of Robinson’s Bend Field Assets
	On February 28, 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama for $63.0 million, subject to closing adjustments that amounted to approximately $4.0 million. We recorded a loss on the sale of approximately $3.1 million in the three months ended March 31, 2013. The sale of the Robinson’s Bend Field assets was initiated to provide the financial flexibility necessary to support our efforts for pursuing opportunities and further developing our properties in the Mid-Continent region, as well as reducing our outstanding debt.
	The following amounts relating to the Robinson’s Bend Field assets have been reported as discontinued operations in the consolidated statements of operations in the years ending December 31, 2013 and 2012 (in thousands):



		Year Ending December 31,
		2013		2012
	Revenues	$	2,304	$	12,808
	Loss from discontinued operations	$	-2,686	$	-77,081
	The loss from discontinued operations for the year ended December 31, 2012 included an impairment charge of approximately $73.3 million to impair the asset group that contained our natural gas properties and inventory in the Robinson’s Bend Field. This impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by the cash offer to purchase the assets for $63.0 million, subject to certain post-closing adjustments.
	See Note 1 for information regarding earnings per unit, including earnings per unit data relating to income from discontinued operations, which includes loss on sale of discontinued operations in 2013.
	The following table provides the major classes of assets and liabilities components of discontinued operations as of December 31, 2013 and 2012 (in thousands):



		December 31,
		2013		2012
	Accounts receivable	$	-	$	1,763
	Natural gas properties, net	$	-	$	67,301
	Total discontinued assets	$	-	$	69,259

	Accounts payable	$	-	$	711
	Accrued liabilities	$	-	$	771
	Asset retirement obligation	$	-	$	7,692
	Total discontinued liabilities	$	-	$	9,270
	The consolidated statements of cash flows reflect discontinued operations for the years ended December 31, 2013 and 2012.

Acquisition

Acquisition	12 Months Ended
Acquisition	Dec. 31, 2013
Acquisition [Abstract]	'
Acquisition	'
	3. ACQUISITION
	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 acquisitions, SEP I received $20.1 million in cash; 1,130,512 Class A units, which represents 70% of the total Class A units, and 4,724,407 Class B units, which represents 16.6% of the total Class B units. 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 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, specifically ad valorem taxes, property taxes, franchise taxes and any other state or local taxes. 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):



	Oil and natural gas properties, equipment and facilities		$	31,497
	Asset retirement obligation			-1,088
	Net assets acquired		$	30,409
	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					Twelve Months Ended
		December 31,					December 31,
		2013			2012		2013		2012
	Revenue	$	3,018		$	5,036	$	15,782	$	20,939
	Lease Operating Expenses	$	819		$	997	$	3,047	$	4,049
	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					Twelve Months Ended
		December 31,					December 31,
	(In thousands)	2013			2012		2013		2012
	Revenue	$	11,458		$	18,473	$	56,841	$	67,466
	Income (loss) from continuing operations	$	-13,066		$	1,093	$	-18,514	$	3,825
	Discontinued operations	$	-		$	-74,055	$	-2,686	$	-77,081
	Net Loss	$	-13,066		$	-72,962	$	-21,200	$	-73,256
	Income (loss) from continuing operations per unit
	Class A units - Basic and diluted	$	-0.16		$	0.01	$	-0.23	$	0.05
	Class B units - Basic and diluted	$	-0.46		$	0.04	$	-0.65	$	0.13
	Discontinued operations per unit
	Class A units - Basic and diluted	$	-		$	-0.92	$	-0.03	$	-0.96
	Class B units - Basic and diluted	$	-		$	-2.55	$	-0.09	$	-2.66
	Net loss per unit
	Class A units - Basic and diluted	$	-0.16		$	-0.9	$	-0.26	$	-0.91
	Class B units - Basic and diluted	$	-0.45		$	-2.52	$	-0.74	$	-2.53
	Weighted average units outstanding
	Class A units - Basic and diluted		1,615,017			1,613,924		1,615,103		1,614,076
	Class B units - Basic and diluted		28,457,577			28,412,032		28,057,592		28,412,353

Fair_Value_Messurements

Fair Value Messurements	12 Months Ended
Fair Value Messurements	Dec. 31, 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 December 31, 2013 (in thousands):



		Fair Value Measurements at December 31, 2013
		Quoted Prices in		Significant other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Dec-13
	Risk Mgmt Assets	$	—	$	11,577	$	—	$	-975	$	10,602
	Risk Mgmt Liabilities		—		-975		—		975		—
	Total Net Assets and Liabilities	$	—	$	10,602	$	—	$	—	$	10,602
	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 December 31, 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 6.
	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	12 Months Ended
Derivative And Financial Instruments	Dec. 31, 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 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 consolidated statements of operations.
	As of December 31, 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
	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	1,215,420		$	4.25		1,153,487		$	4.25	1,096,023	$	4.26	1,050,219	$	4.26	4,515,149	$	4.26
	2016	1,010,633		$	4.21		967,290		$	4.21	923,541	$	4.21	893,568	$	4.22	3,795,032	$	4.21
																	14,697,681
	MTM Fixed Price Basis Swaps – Enable Gas Transmission, LLC (East), ONEOK Gas Transportation (Oklahoma) or Southern Star Central Gas Pipeline (Texas, Oklahoma and Kansas)



		For the quarter ended (in MMBtu)
		March 31,					June 30,				September 30,			December 31,			Total
				Weighted					Weighted			Weighted			Weighted			Weighted
		Volume		Average $			Volume		Average $		Volume	Average $		Volume	Average $		Volume	Average $
	2014	1,178,422		$	0.39		1,133,022		$	0.39	1,084,270	$	0.39	1,047,963	$	0.39	4,443,677	$	0.39
																	4,443,677
	MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI)



		For the quarter ended (in Bbls)
		March 31,					June 30,				September 30,			December 31,			Total
				Average					Average			Average			Average			Average
		Volume		Price			Volume		Price		Volume	Price		Volume	Price		Volume	Price
	2014	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
																	464,406
	The table below outlines the classification of our derivative financial instruments on the consolidated balance sheets (in thousands):



					Fair Value of Asset/(Liability)
			Location of Asset/(Liability)		On Balance Sheet
	Derivative Type		On Balance Sheet		31-Dec-13			31-Dec-12

	Commodity – MTM		Risk management assets - current		$	10,043		$	19,005
	Commodity – MTM		Risk management assets - non-current			1,534			12,025
			Total gross assets			11,577			31,030

	Commodity – MTM		Risk management assets – current			-903			-1,040
	Commodity – MTM		Risk management assets – non-current			-72			-946
	Commodity – MTM		Risk 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			-975			-6,794
			Total net assets and liabilities		$	10,602		$	24,236




	The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands):




				Amount of Gain/(Loss) in Income
		Location of Gain/(Loss)		For the Year Ended December 31,
Derivative Type		in Income		2013			2012

Commodity – MTM		Oil and natural gas sales		$	-1,486		$	15,701
Interest Rate – MTM		Interest expense			-65			-1,061
		Total		$	-1,551		$	14,640










				Amount of Gain/(Loss) Reclassified from
		Location of Gain/(Loss) for		AOCI into Income – Effective
		Effective and Ineffective		For the Three Months Ended December 31,
Derivative Type		Portion of Derivative in Income		2013			2012

Commodity – Cash Flow		Natural gas sales		$	—		$	1,271
		Total		$	—		$	1,271
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 my 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 December 31, 2013 and 2012, respectively, the impact of non-performance credit risk on the valuation of our net assets from counterparties was not significant
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 hedges were executed prior to December 31, 2013.
Hedge Liquidation, Repositioning and Novation
In connection with the sale of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama, we liquidated 395,218 MMbtu of NYMEX swaps in 2013 and 1,634,530 MMbtu of NYMEX swaps in 2014 at a cost of $0.3 million. In addition, we reduced our outstanding NYMEX swap positions in 2013 by 1,041,814 MMbtu by executing offsetting trades with one of our counterparties at a fixed price of $3.66 per Mcf. These transactions 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 per barrel, on a total of 58,157 barrels of oil. We received proceeds of approximately $0.2 million upon execution of the amendment. The proceeds were used for working capital purposes.
In March 2013, we reduced our outstanding interest rate swaps that fixed our LIBOR rate through 2014 to $30 million, which resulted in additional interest rate swap settlements of $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.
In May 2013, in conjunction with amendments to our reserve-based credit facility and the exit of certain lenders from our bank syndicate, we novated certain of our commodity hedges to Societe General, which increased our natural gas settlement cost by $0.3 million.

Debt

Debt	12 Months Ended
Debt	Dec. 31, 2013
Debt [Abstract]	'
Debt	'
	6. DEBT
	Reserve-Based Credit Facility
	In May 2013, we refinanced our $350.0 million reserve-based credit facility with Societe Generale as administrative and collateral agent and a syndicate of lenders, extending its maturity to May 30, 2017 and increasing our borrowing base from $37.5 million to $55.0 million. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own, as well as various security and pledge agreements among us and certain of our subsidiaries and the administrative agent. The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties. As of December 31, 2013, we had borrowed $50.7 million under our reserve-based credit facility and our borrowing base was $55.0 million. At December 31, 2013, the lenders and their percentage commitments in the reserve-based credit facility were Societe Generale (36.36%), OneWest Bank, FSB (36.36%) and BOKF NA, dba Bank of Oklahoma (27.28%).
	Borrowings under the reserve-based credit facility are available for acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes. The reserve-based credit facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit. As of December 31, 2013, no letters of credit were outstanding.
	At our election, interest for borrowings is determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (ABR) plus an applicable margin between 1.50% and 2.50% per annum based on utilization plus (iii) a commitment fee of 0.50% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans 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, make certain loans, acquisitions, capital expenditures and investments. The reserve-based credit facility limits our ability to pay distributions to unitholders and permits us to hedge our projected monthly production, as discussed below, and the interest rate on our borrowings.
	In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents and cash reserves of the Company)) to Adjusted EBITDA (generally, for any period, the sum of consolidated net income for such period plus (minus) the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives, and other similar charges) of not more than 3.50 to 1.0; (ii) Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and (iii) consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt (to the extent such payments are not past due), of not less than 1.0 to 1.0, all calculated pursuant to the requirements under Accounting Standards Codification (ASC) Topic 815, Derivatives and Hedging; ASC Topic 410, Asset Retirement and Environmental Obligations and ASC Topic 360, Property, Plant and Equipment. All financial covenants are calculated using our consolidated financial information and are discussed below.
	The reserve-based credit facility also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, guaranties not being valid under the reserve-based credit facility and a change of control. A change of control is generally defined as the occurrence of both of the following events: (i) wholly-owned subsidiaries of Constellation Energy Group, Inc. are the owner of 20% or less of an interest in us (which has now occurred) and (ii) any person or group of persons acting in concert are the owner of more than 35% of an interest in us. These events have not both occurred, so a change in control had not occurred as of December 31, 2013. If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise other rights and remedies. The reserve-based credit facility contains a condition to borrowing and a representation that no material adverse effect (MAE) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of us and our subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable.
	The reserve-based credit facility limits our ability to pay distributions to unitholders. We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the reserve-based credit facility exceed 90% of our borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by our board of managers for the proper conduct of our business and the payment of fees and expenses. As of December 31, 2013, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to pay distributions.
	The reserve-based credit facility permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve-month period, the volumes of production hedged in any month may not exceed our reasonable business judgment of the production for such month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then-current strip pricing (provided that such projection shall not be more than 115% of the proved developed producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for the period beyond twelve months, the volumes of production hedged in any month may not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers. The reserve-based credit facility also permits us to hedge the interest rate on up to 90% of the then-outstanding principal amounts of our indebtedness for borrowed money.
	The reserve-based credit facility contains no covenants related to PostRock’s, Exelon’s or SOG’s ownership in us.
	Compliance with Financial Covenants
	At December 31, 2013, we were in compliance with the financial covenant ratios contained in our reserve-based credit facility. We monitor compliance on an ongoing basis. As of December 31, 2013, our actual Total Net Debt to annual Adjusted EBITDA ratio was 2.6 to 1.0, compared to a required ratio of not greater than 3.5 to 1.0; our actual ratio of consolidated current assets to consolidated current liabilities was 1.3 to 1.0, compared to a required ratio of not less than 1.0 to 1.0 and our actual quarterly Adjusted EBITDA to cash interest expense ratio was 9.3 to 1.0, compared to a required ratio of not less than 2.5 to 1.0.

	If we are unable to remain in compliance with the financial covenants contained in our reserve-based credit facility or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of our reserve-based credit facility, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.

	The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural gas properties. As of December 31, 2013, our borrowing base was $55.0 million. The borrowing base is re-determined semi-annually, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas prices prevailing at such time. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders.

	Funds Available for Borrowing
	As of December 31, 2013, we had $50.7 million in outstanding debt under our reserve-based credit facility and $4.3 million in remaining borrowing capacity. At December 31, 2012, we had $84 million in outstanding debt under our reserve-based credit facility.
	Debt Issue Costs
	As of December 31, 2013, our unamortized debt issue costs were approximately $0.8 million. These costs are being amortized over the life of the credit facility. At December 31, 2012, our unamortized debt issue costs were approximately $1.2 million.

Oil_And_Natural_Gas_Properties

Oil And Natural Gas Properties	12 Months Ended
Oil And Natural Gas Properties	Dec. 31, 2013
Oil And Natural Gas Properties [Abstract]	'
Oil And Natural Gas Properties	'
	7. OIL AND NATURAL GAS PROPERTIES
	Oil and natural gas properties consist of the following (in thousands):




		December 31,
		2013		2012
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	636,816	$	591,889
	Unproved property		1,589		1,380
	Total property costs		638,405		593,269
	Materials and supplies		1,054		771
	Land		751		751
	Total		640,210		594,791
	Less: Accumulated depreciation, depletion, amortization and impairments		-495,215		-474,669
	Oil and natural gas properties and equipment, net	$	144,995	$	120,122


	Depreciation, depletion, amortization and impairments consisted of the following (in thousands):




		Year Ended December 31,
		2013		2012

	DD&A of oil and natural gas-related assets	$	18,972	$	11,732
	Asset Impairments		2,357		109
	Total	$	21,329	$	11,841
	Impairment Charges
	Our non-cash asset impairment charges for the year ended December 31, 2013 were $2.3 million, compared to $0.1 million for the same period in 2012. Our non-cash impairment charges in 2013 were approximately $2.1 million to impair the value of our oil and natural gas fields in Texas and Louisiana and $0.2 million to impair certain of our wells in the Woodford Shale.
	Our non-cash impairment charges in 2012 were approximately $0.1 million to impair certain properties in the Woodford Shale. The impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash flows reported in a third party reserve report.
	Asset Sales
	In 2012, we sold our interests in 14 gross non-operated oil wells in Kansas and Nebraska for approximately $1.4 million in cash, and sold approximately $0.1 million in trucks and equipment resulting in no material gain or loss on the asset sales.
	Useful Lives
	Our furniture, fixtures and equipment are depreciated over a life of one to seven years, buildings are depreciated over a life of 20 years and pipeline and gathering systems are depreciated over a life of 25 to 40 years.

	Exploration and Dry Hole Costs
	We recorded no exploration and dry hole costs for the years ended December 31, 2013 and 2012. These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties.

Benefit_Plans

Benefit Plans	12 Months Ended
Benefit Plans	Dec. 31, 2013
Benefit Plans [Abstract]	'
Benefit Plans	'
	8. BENEFIT PLANS
	Eligible employees of CEP participate in an employment savings plan. Matching contributions made by us were approximately $0.3 million and $0.5 million years ended December 31, 2013 and 2012, respectively.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transations	'
	9. RELATED PARTY TRANSACTIONS
	Unit Ownership
	PostRock, Exelon and SOG, through subsidiaries, own a portion of our outstanding units. As of December 31, 2013, CEPM, a subsidiary of PostRock, owned 484,505, or 30%, 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 December 31, 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.
	PostRock-Related Announcements
	In 2011, PostRock acquired certain of our Class A units and Class B common units in two separate transactions which represented a 21.3% ownership interest in us at December 31, 2013. Approval of the purchase of these units was neither required nor given by our board of managers or conflicts committee. We believe PostRock is now an “interested unitholder” under Section 203 of the Delaware General Corporation Law, which is applicable to us pursuant to our operating agreement. Section 203, as it applies to us, prohibits an interested unitholder, defined as a person who owns 15% or more of our outstanding common units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder without the approval of our board of managers and the vote of 66 2/3% of our outstanding Class B common units, excluding those held by the interested unitholder. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. In addition to limiting our ability to enter into transactions with PostRock or its affiliates, this provision of our operating agreement could have an anti-takeover effect with respect to transactions not approved in advance by our board of managers, including discouraging takeover attempts that might result in a premium over the market price for our common units. We believe the Section 203 restrictions related to these unit purchases expire in December 2014.

	Sanchez-Related Announcements
	In August 2013, SOG acquired certain of our Class A units and Class B common units and one Class Z unit in one transaction which represented a 19.5% ownership interest in us at December 31, 2013. These units were issued to SOG, along with cash, in exchange for oil and natural gas properties located in Texas and Louisiana.
	In August 2013, the Company also entered into a Registration Rights Agreement with SOG pursuant to which the Company granted to SOG certain registration rights related to the unit consideration thereunder. Under the Registration Rights Agreement, the Company granted SOG demand registration rights with respect to the preparation and filing with the SEC of one or more registration statements for the purpose of registering the resale of the securities that will be registered.

	Class C Management Incentive Interests
	CEPH, a subsidiary of Exelon, holds the Class C management incentive interests in CEP. 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 or share in distributions upon liquidation.

	Class D Interest
	The majority of our properties in the Robinson’s Bend Field were subject to a non-operated net profits interest (NPI) held by Torch Energy Royalty Trust (the Trust). Through the NPI, the Trust was entitled to a royalty payment, calculated as a percentage of the net revenue from specified wells in the Robinson’s Bend Field (the Trust Wells).
	Under the terms of the NPI and related contractual arrangements, the royalty payment we were required to make to the Trust under the NPI was calculated using a sharing arrangement with a pricing formula that had resulted in below-market prices and had the effect of keeping our payments to the Trust significantly lower than if such payments had been calculated on then prevailing market prices.
	In order to address the risks of early termination, without the prior consent of our board of managers, of the sharing arrangement in respect of the calculation of amounts payable to the Trust for the NPI and the potential reduction in our revenues resulting therefrom, Constellation Holdings, Inc. (CHI) contributed $8.0 million to us for all of our Class D interests. This contribution was potentially to be distributed to CHI in 24 distributions over a period of approximately six years if the sharing arrangement remained in effect during that period. If the amounts payable by us to the Trust were not calculated based on the continued applicability of the sharing arrangement through December 31, 2012, unless such change was approved in advance by our board of managers and our conflicts committee, the following would occur: the Class D interests would cease receiving the cash distributions; and the Class D interest would only be returned the remaining undistributed amount of the $8.0 million contribution under certain circumstances upon our liquidation.
	No payments for the NPI were ever made to the Trust. On January 8, 2009, we were served by Trust Venture, on behalf of the Trust, with a purported derivative action filed in the Circuit Court of Tuscaloosa County, Alabama (the Circuit Court). The lawsuit alleged, among other things, a breach of contract under the conveyance associated with the NPI and the agreement establishing the Trust and asserted that above market rates for services were paid, reducing the amounts paid to the Trust in connection with the NPI. The lawsuit sought unspecified damages and an accounting of the NPI. The lawsuit was settled in June 2011. The settlement with Trust Venture, its successor and the Trust provided, among other things, that we pay $1.2 million to reimburse Trust Venture and its successor for their legal fees and expenses incurred in prosecuting the lawsuit and that we acquire the NPI from the Trust for $1.0 million. When the NPI was assigned to us by the Trust in the fourth quarter of 2011, the NPI was extinguished. We recognized a $1.0 million charge to impair the value of the extinguished NPI contract that was acquired. The finalization of this settlement impacted our Class D interests. The NPI no longer burdened our properties in the Robinson’s Bend Field upon their sale in February 2013.
	CEPH, a subsidiary of Exelon and the successor to CHI, holds all of our Class D interests. Due to their contingently redeemable feature, the Class D interests were treated as temporary equity. Since the NPI is no longer being paid based upon the sharing arrangement and we have suspended distributions since June 2009, there should be no further distributions required on the Class D interests. Accordingly, the Class D interests were moved from temporary equity to permanent equity (Class A and Class B) in the fourth quarter of 2011. The Class D interests will remain outstanding until the liquidation of CEP and could receive up to $6.7 million under certain circumstances at that time.
	Class Z Unit
	SOG holds the one Class Z unit of CEP. This one unit is a non-voting unit, except voting as a separate class must approve the issuance of additional Company securities, other than Class B common units, prior to the issuance of such securities. The Class Z unit is a non-economic interest, without any right to participate in distributions or allocations.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
Commitments And Contingencies	Dec. 31, 2013
Commitments And Contingencies [Abstract]	'
Commitments And Contingencies	'
	10. 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 natural 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 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 parties to the lawsuit are currently working on the terms of a settlement agreement. In anticipation of a settlement being reached, we have accrued a probable liability of $5.9 million.

Asset_Retirement_Obligation

Asset Retirement Obligation	12 Months Ended
Asset Retirement Obligation	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	11. 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):




		December 31,
		2013		2012
	Asset retirement obligation, beginning balance	$	7,665	$	7,052
	Liabilities added from acquisitions		1,088		-
	Liabilities added from drilling		244		162
	Settlements		-3		-8
	Accretion expense		519		459
	Asset retirement obligation, ending balance	$	9,513	$	7,665

	Additional 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 obligation. In 2013 and 2012, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations.

UnitBased_Compensation

Unit-Based Compensation	12 Months Ended
Unit-Based Compensation	Dec. 31, 2013
Unit-Based Compensation [Abstract]	'
Unit-Based Compensation	'
	12. UNIT-BASED COMPENSATION
	We have the following unit-based compensation plans:
	We have the 2009 Omnibus Incentive Compensation Plan (Omnibus Plan), which is a plan under which restricted common unit awards are granted to certain employees in Texas. The Omnibus Plan provides for a variety of unit-based and performance-based awards, including unit options, restricted units, unit grants, notional units, unit appreciation rights, performance awards and other unit-based awards. Awards under the Omnibus Plan may be paid in cash, units or any combinations thereof as determined by the compensation committee of our board of managers.
	Restricted unit activity (number of units) under the Omnibus Plan was as follows:



			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit

	Outstanding at December 31, 2011	962,281	$	3.41
	Vested	-215,308		3.40
	Granted	7,190		1.32
	Returned/Cancelled	-87,385		3.40
	Outstanding at December 31, 2012	666,778		3.39
	Vested	-370,363		2.66
	Granted	184,313		1.27
	Returned/Cancelled	-144,177		2.77
	Outstanding at December 31, 2013	336,551	$	3.29

	We have the Long-Term Incentive Program (L-TIP), which is a plan under which restricted common unit awards are granted to certain field employees in Alabama, Kansas and Oklahoma and to certain employees in Texas.



	Restricted unit activity (number of units) under the L-TIP Plan was as follows:



			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit

	Outstanding at December 31, 2011	149,869	$	3.44
	Vested	-56,025		3.42
	Granted	30,000		2.17
	Returned/Cancelled	-28,930		3.42
	Outstanding at December 31, 2012	94,914		3.05
	Vested	-61,273		2.24
	Granted	38,023		1.17
	Returned/Cancelled	-27,888		2.56
	Outstanding at December 31, 2013	43,776	$	2.87

	We recognized approximately $1.0 million and $1.5 million of non-cash compensation expense related to our unit-based compensation plans in the twelve months ended December 31, 2013 and 2012, respectively. As of December 31, 2013, we had approximately $0.5 million in unrecognized compensation expense related to our unit-based compensation plans expected to be recognized through the first quarter of 2015.

Distributions_To_Unitholders

Distributions To Unitholders	12 Months Ended
Distributions To Unitholders	Dec. 31, 2013
Distributions To Unitholders [Abstract]	'
Distributions To Unitholders	'
	13. DISTRIBUTIONS TO UNITHOLDERS

	Beginning in June 2009, we suspended our quarterly distributions to unitholders. For twelve months ended December 31, 2013 and 2012, respectively, 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	12 Months Ended
Members' Equity	Dec. 31, 2013
Members' Equity [Abstract]	'
Members' Equity	'
	14. MEMBERS’ EQUITY
	2013 Equity
	At December 31, 2013, we had 1,615,017 Class A units and 28,462,185 Class B common units outstanding, which included 43,776 unvested restricted common units issued under our Long-Term Incentive Plan and 336,551 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan.
	At December 31, 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 December 31, 2013, we had granted 1,366,666 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 1,030,115 have vested.
	For the year ended December 31, 2013, 139,810 common units were 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 December 31, 2012, we had 483,418 Class A units and 23,687,507 Class B common units outstanding, which included 94,914 unvested restricted common units issued under our Long-Term Incentive Plan and 666,778 unvested restricted common units issued under our 2009 Omnibus Incentive Compensation Plan.
	At December 31, 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. Of these grants, 38,023 have vested.
	At December 31, 2012, we had granted 1,326,530 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 659,752 have vested. We also granted an additional 323,194 performance units under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 161,597 have vested.
	For the year ended December 31, 2012, 90,425 common units were tendered by our employees for tax withholding purposes. These units, costing approximately $0.2 million, were returned to their respective plan and are available for future grants.

Supplemental_Information_On_Oi

Supplemental Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2013
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]	'
Supplemental Information On Oil And Natural Gas Producing Activities	'
	15.SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
	The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance. The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities.
	Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves.
	In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama. Information related to these assets is classified as discontinued operations.

	Costs
	The following table sets forth capitalized costs for the years ended December 31, 2013 and 2012 (in thousands):




		December 31,
		2013			2012
	Capitalized costs at the end of the period:⁽ᵃ⁾
	Oil and natrual gas properties and related equipment (successful efforts method)
	Property costs
	Proved property	$	636,816		$	591,889
	Unproved property		1,589			1,380
	Total property costs		638,405			593,269
	Materials and supplies		1,054			771
	Land		751			751
	Total		640,210			594,791
	Less: Accumulated depreciation, depletion, amortization and impairments		-495,215			-474,669
	Oil and natural gas properties and equipment, net	$	144,995		$	120,122

	(a)Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.
	The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2013 and 2012 (in thousands):




		For the year ended December 31,
		2013			2012
	Costs incurred for the period:
	Acquisition of properties
	Proved	$	20,012		$	75
	Unproved		209			177
	Development costs		15,694			15,336
	Oil and natural gas properties and equipment, net	$	35,915		$	15,588

	The development costs for the years ended December 31, 2013 and 2012 primarily represent costs to develop our proved undeveloped reserves. The properties acquired in 2013 were in Texas and Louisiana.

	We had no exploration and dry hole costs in 2013 and 2012, respectively.
	Results of Operations
	The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations and Comprehensive Income (Loss). All of our operations are oil and natural gas producing activities located in the United States.
	Net Proved Oil and Natural Gas Reserves
	The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States.




		For the year ended December 31,
		2013		2012
	(In Mmcfe)
	Beginning balance	92,982		201,330
	Extensions and discoveries	4,825		2,049
	Purchases of reserves in place	7,150		-
	Sales of reserves in place	-49,385		-256
	Revisions of previous estimates	44,727		-97,178
	Production	-9,045		-12,963
	Ending balance	91,254		92,982

	Ending balance from continuing operations	91,254		43,596
Ending balance from discontinued operations⁽ᵃ⁾	-		49,386
Total ending balance	91,254		92,982

Proved developed reserves from continuing operations	78,629		40,867
Proved developed reserves from discontinued operations	-		49,134
Total proved developed reserves	78,629		90,001

Proved undeveloped reserves from continuing operations	12,625		2,729
Proved undeveloped reserves from discontinued operations	-		252
Total proved undeveloped reserves	12,625		2,981
⁽ᵃ⁾ In February 2013, we sold all of our Black Warrior Basin properties.
Reserves and Related Estimates
Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.
Our December 31, 2013 and 2012 proved reserve estimates were 91.3 Bcfe and 93.0 Bcfe, respectively. For these years, NSAI, an independent petroleum engineering firm, prepared the estimates of our proved reserves which were used to prepare our financial statements.
Our 2013 estimates of total proved reserves decreased 1.7 Bcfe from 2012 due to the sale of our Black Warrior Basin properties in the amount of 49 Bcfe offset by the acquisition of the Sanchez properties, which added 7 Bcfe. We added 4.8 Bcfe due to extensions and discoveries in the Cherokee Basin reserves added for oil opportunities. Our reserve revisions of 44.8 Bcfe are primarily the result of higher natural gas prices. Our reserves are 85% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For the proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $97.89 per barrel for oil, $41.21 per barrel for natural gas liquids and $3.706 per Mcf for natural gas. Any of our locations that are scheduled to be drilled after 5 years are classified as probable or possible reserves to the extent they are economic.
Our 2012 estimates of total proved reserves decreased 108.3 Bcfe from 2011 due to a lower SEC-required price for natural gas used to calculate our reserves in 2012. We added 2.0 Bcfe due to extensions and discoveries in the Cherokee Basin reserves added for oil opportunities and 0.2 Bcfe of natural gas reserves. Our reserve revisions of 97.2 Bcfe are primarily the result of lower natural gas prices causing our reserves to no longer be considered economic under SEC rules. Our reserves are 93% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. Although we utilize swaps and basis swaps to mitigate commodity price risk and basis differentials, these derivatives are not used when preparing our reserve report based on SEC rules. The SEC-required price used to prepare our reserve report was $2.91 in the Cherokee Basin and $2.85 in the Black Warrior Basin. The SEC-required prices used in the Cherokee Basin and in the Black Warrior Basin declined from 2011 to 2012 by $0.97 and $1.35, respectively. Our actual 2012 production of 12.6 Bcfe is 3.8 Bcfe higher than what our 2011 reserve report estimated for 2012. A significant number of our wells that actually produced natural gas in 2012 were not included in our 2011 reserve report as they were deemed uneconomic at the SEC-required price which excludes the impact of our swaps and basis swaps used to mitigate commodity price risk and basis differentials. Any of our locations that are scheduled to be drilled after 5 years are classified as probable or possible reserves to the extent they are economic.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Including a Reconciliation of Changes Therein
The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below.
Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because CEP is a non-taxable entity.
The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.
The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands):




		For the year ended December 31,
		2013			2012
Future cash inflows		$	502,831		$	360,825
Future production costs			-227,315			-194,198
Future estimated development costs			-40,694			-11,124
Future net cash flows			234,822			155,503
10% annual discount for estimated timing of cash flows			-91,108			-65,834
Standardized measure of discounted estimated future net cash
	flows related to proved gas reserves	$	143,714		$	89,669

Standardized measure from continuing operations			143,714			60,455
Standardized measure from discontinued operations⁽ᵃ⁾			-			29,214
Standardized measure of discounted estimated future net cash
	flows related to proved gas reserves	$	143,714		$	89,669
⁽ᵃ⁾ In February 2013, we sold all of our Black Warrior Basin properties.




The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands):




		For the year ended December 31,
		2013			2012
Beginning of the period		$	89,669		$	160,691
Sales and transfers of oil and natural gas, net of production costs			-21,244			-39,699
Net changes in prices and production costs related to future production			50,425			-19,228
Development costs incurred during the period			5,615			18,818
Changes in extensions and discoveries			28,494			12,590
Revisions of previous quantity estimates			21,455			-83,750
Sales of reserves in place			-2,297			-1,476
Accretion discount			8,967			16,069
Other			-37,370			25,654
Standardized measure of discounted future net cash flows related to
	proved gas reserves	$	143,714		$	89,669

Standardized measure from continuing operations			143,714			60,455
Standardized measure from discontinued operations⁽ᵃ⁾			-			29,214
Standardized measure of discounted future net cash flows related to
	proved gas reserves	$	143,714		$	89,669
⁽ᵃ⁾ In February 2013, we sold all of our Black Warrior Basin properties.

Subsequent_Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	16. SUBSEQUENT EVENTS
	The following events have occurred subsequent to the date of the balance sheet or prior to the filing of this Annual Report on Form 10-K that could have a material impact on our consolidated financial statements or results of operations:

	On February 28, 2014, a lawsuit was filed in the Chancery Court of the State of Delaware by CEPH against the Company (the Exelon Litigation) seeking repayment of suspended distributions in relation to the Class D Interests held by CEPH. In 2006, Constellation Holding, Inc (CHI), which merged with and into CEPH in December 2012, purchased the Company’s Class D Interests for $8.0 million. The $8.0 million was to be repaid to CEPH in quarterly distributions of $333,333.33 over a period of six years; however, these distributions could be temporarily suspended if a dispute arose over pricing formulas related to the sale of natural gas from the Robinson’s Bend properties. A dispute arose, so the distributions were suspended pursuant to the Company’s operating agreement and never reinstated. CEPH contends, among other things, that the Company breached its contract to pay the quarterly distributions, acted in bad faith and received unjust enrichment by suspending the quarterly distributions. The Company believes that the allegations contained in the lawsuit are without merit and intends to vigorously defend itself against the claims raised in the complaint. In conjunction with its defense in the Exelon Litigation, the Company anticipates that it will incur legal and other costs that may have a material effect on available cash which could impact CEP’s ability to make distributions

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
Summary Of Significant Accounting Policies (Policies)	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Organization And Basis Of Presentation	'
	Organization and Basis of Presentation
	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 December 31, 2013, Constellation Energy Partners Management, LLC (CEPM), a subsidiary of PostRock, owned 484,505, or 30%, 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), an affiliate 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.
	Accounting policies used by us conform to accounting principles generally accepted in the United States of America. The accompanying financial statements include the accounts of us 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.

Use Of Estimates	'
	Use of Estimates
	Estimates and assumptions are made when preparing financial statements under accounting principles generally accepted in the United States of America. These estimates and assumptions affect various matters, including:
	•reported amounts of revenue and expenses in the Consolidated Statements of Operations and Other Comprehensive Loss during the reported periods,
	•reported amounts of assets and liabilities in the Consolidated Balance Sheets at the dates of the financial statements,

	•disclosure of quantities of reserves and use of those reserve quantities for depreciation, depletion and amortization, and
	•disclosure of contingent assets and liabilities at the date of the financial statements.
	These estimates involve judgments with respect to numerous factors that are difficult to predict and are beyond management’s control. As a result, changes in facts and circumstances or additional information may result in revised estimates or actual amounts may materially differ from these amounts.

Reclassifications	'
	Reclassifications
	Certain reclassifications have been made to the prior periods to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.

Discontinued Operations	'
	Discontinued Operations
	In February 2013, we sold all of our Robinson’s Bend Field assets in the Black Warrior Basin of Alabama. The related results of operations and cash flows have been classified as discontinued operations in the consolidated statements of operations, balance sheets, statements of cash flows and consolidated financial information. Unless otherwise indicated, information presented in the Notes to Consolidated Financial Statements relates only to the Company’s continuing operations. Information related to discontinued operations is included in Note 2. Discontinued Operations.

Cash And Cash Equivalents	'
	Cash and Cash Equivalents
	All highly liquid investments with original maturities of three months or less are considered cash equivalents. Checks-in-transit were none in 2013 and $0.6 million in 2012 and are included in accounts payable in our consolidated balance sheets.

Restricted Cash	'
	Restricted Cash
	Restricted cash at December 31, 2013 of $1.7 million is held in escrow in relation to the sale of the Robinson’s Bend Field assets and related to litigation involving one of our service providers. Restricted cash at December 31, 2012 was comprised of $0.6 million held in escrow related to litigation involving one of our service providers.

Concentration Of Credit Risk And Accounts Receivable	'
	Concentration of Credit Risk and Accounts Receivable
	Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our reserve-based credit facility and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from purchasers of oil and natural gas. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was less than $0.1 million in each of 2012 and 2013. We have no off-balance-sheet credit exposure related to our operations or customers.

	For the year ended December 31, 2013, five customers accounted for approximately 22%, 20%, 17%, 14% and 8% of our sales revenues. For the year ended December 31, 2012, five customers accounted for approximately 28%, 10%, 9%, 9% and 8% of our sales revenues.

Oil And Natural Gas Properties	'
	Oil and Natural Gas Properties
	Oil and Natural Gas Properties
	We follow the successful efforts method of accounting for our oil and natural gas exploration, development and production activities. Leasehold acquisition costs, property acquisition and the costs of development of proved areas are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred.
	Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place.
	Depreciation, Depletion and Amortization
	Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. It has been our historical practice to use our year-end reserve report to adjust our depreciation, depletion, and amortization expense for the fourth quarter. Depreciation, depletion, and amortization expense is calculated using year-end reserve reports based on the SEC-required price. As more fully described in Note 15, proved reserves estimates are subject to future revisions when additional information becomes available.
	Asset Retirement Obligation
	As described in Note 11, estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.
	Unsuccessful Wells
	Geological, geophysical and dry hole costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred.
	Impairment
	Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Cash flow estimates for the impairment testing exclude derivative instruments. Refer to Note 7 for additional information.
	Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that we expect to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually.
	Property acquisition costs are capitalized when incurred.
	Support Equipment and Facilities
	Support equipment and facilities consist of certain of our water treatment facilities, gathering lines, roads, pipelines and other various support equipment. Items are capitalized when acquired and depreciated using the straight-line method over the useful life of the assets.
	Materials and Supplies
	Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.

Oil And Natural Gas Reserve Quantities	'
	Oil and Natural Gas Reserve Quantities
	Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2013 and 2012 is described in detail in Note 15.
	Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates.
	Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Derivatives And Hedging Activities	'
	Derivatives and Hedging Activities
	We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure on our borrowings under our reserve-based credit facility.
	We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheet as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price or interest rate exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets under the captions “Risk management assets” and “Risk management liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations and comprehensive income (loss) under the caption “Oil and liquid sales” or “Natural gas sales” and settled interest rate swaps as “Interest expense.”

Revenue Recognition	'
	Revenue Recognition
	Sales of oil and natural gas are recognized when oil or natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale are reasonably assured and the sales price is fixed or determinable. Oil and natural gas is sold on a monthly basis. Most of our sales contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil or natural gas, and prevailing supply and demand conditions, so that the price of the oil or natural gas fluctuates to remain competitive with other available energy supplies. As a result, revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our oil and natural gas contracts are customary in the industry.
	Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no gas imbalance positions at December 31, 2013 or 2012, respectively.

Income Taxes	'
	Income Taxes
	CEP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of its members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. CEP is subject to franchise tax obligations in Kansas and Texas and state tax obligations in Alabama and Oklahoma. CEP also has informational filing requirements in Georgia, Indiana, Louisiana, Maine, Missouri, New Jersey, New York, Oregon, Pennsylvania, and West Virginia because we have resident unitholders in these states.
	Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2013, and 2012, the current federal and state tax liability for the entity was less than $0.1 million and $0.1 million, respectively. The entity has no deferred tax assets or liabilities. Taxes are paid to the IRS or the applicable states in quarterly installments.

Earnings Per Unit	'
	Earnings per Unit
	Basic earnings per unit (EPU) is computed by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocate net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) is allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period.
	As of December 31, 2013 and 2012, we had unvested restricted common units outstanding, which were considered dilutive securities. These units will be considered in the diluted weighted average common units outstanding number in periods of net income. In periods of net losses, these units are excluded for the diluted weighted average common unit outstanding number as they are not participating securities.
	The following table presents our calculation of basic and diluted units outstanding for the periods indicated:





		Year Ended December 31,
		2013		2012
	Weighted average units outstanding during period:
	Class A units - Basic and Diluted		933,613		483,564
	Class B Common units - Basic and Diluted		25,210,106		23,687,946
			26,143,719		24,171,510

	At December 31, 2013, we had 380,327 Class B common units that were restricted unvested common units granted and outstanding. These units were excluded from the diluted weighted average common unit outstanding number.

	The following table presents our basic and diluted income per unit for the year ended December 31, 2013 (in thousands, except for per unit amounts):




		Total		Class A Units		Class B Units

	Loss from continuing operations	$	-25,857
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-25,857		-517		-25,340
	Discontinued operations		-2,686		-54		-2,632
	Assumed net loss to be allocated	$	-28,543	$	-571	$	-27,972

	Basic and diluted loss from continuing operations per unit			$	-0.55	$	-1.01
	Basic and diluted loss from discontinued operations per unit			$	-0.06	$	-0.1
	Basic and diluted loss per unit			$	-0.61	$	-1.11




	The following table presents our basic and diluted income per unit for the year ended December 31, 2012 (in thousands, except for per unit amounts):




		Total		Class A Units		Class B Units

	Loss from continuing operations	$	-9,462
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-9,462		-189		-9,273
	Discontinued operations		-77,081		-1,542		-75,539
	Assumed net loss to be allocated	$	-86,543	$	-1,731	$	-84,812

	Basic and diluted loss from continuing operations per unit			$	-0.39	$	-0.39
	Basic and diluted loss from discontinued operations per unit			$	-3.19	$	-3.19
	Basic and diluted loss per unit			$	-3.58	$	-3.58


Comprehensive Loss	'



		Total		Class A Units		Class B Units

	Loss from continuing operations	$	-9,462
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-9,462		-189		-9,273
	Discontinued operations		-77,081		-1,542		-75,539
	Assumed net loss to be allocated	$	-86,543	$	-1,731	$	-84,812

	Basic and diluted loss from continuing operations per unit			$	-0.39	$	-0.39
	Basic and diluted loss from discontinued operations per unit			$	-3.19	$	-3.19
	Basic and diluted loss per unit			$	-3.58	$	-3.58
	Comprehensive Loss
	Comprehensive loss includes net earnings (loss) as well as unrealized gains and losses on derivative instruments that were previously accounted for as cash flow hedges.

Environmental Cost	'
	Environmental Cost
	We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Federal Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

Unit-Based Compensation	'
	Unit-Based Compensation
	We record compensation expense for all equity grants issued under the Long-Term Incentive Program and the 2009 Omnibus Incentive Compensation Plan based on the fair value at the grant date, recognized over the vesting period.

Other Contingencies	'
	Other Contingencies
	We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
Summary Of Significant Accounting Policies (Tables)	Dec. 31, 2013
Summary Of Significant Accounting Policies [Abstract]	'
Schedule Of Weighted Average Units Outstanding	'


		Year Ended December 31,
		2013		2012
	Weighted average units outstanding during period:
	Class A units - Basic and Diluted		933,613		483,564
	Class B Common units - Basic and Diluted		25,210,106		23,687,946
			26,143,719		24,171,510


Earnings Per Common Unit Amounts	'
	The following table presents our basic and diluted income per unit for the year ended December 31, 2013 (in thousands, except for per unit amounts):




		Total		Class A Units		Class B Units

	Loss from continuing operations	$	-25,857
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-25,857		-517		-25,340
	Discontinued operations		-2,686		-54		-2,632
	Assumed net loss to be allocated	$	-28,543	$	-571	$	-27,972

	Basic and diluted loss from continuing operations per unit			$	-0.55	$	-1.01
	Basic and diluted loss from discontinued operations per unit			$	-0.06	$	-0.1
	Basic and diluted loss per unit			$	-0.61	$	-1.11




	The following table presents our basic and diluted income per unit for the year ended December 31, 2012 (in thousands, except for per unit amounts):




		Total		Class A Units		Class B Units

	Loss from continuing operations	$	-9,462
	Distributions		-	$	-	$	-
	Assumed allocation of loss from continuing operations		-9,462		-189		-9,273
	Discontinued operations		-77,081		-1,542		-75,539
	Assumed net loss to be allocated	$	-86,543	$	-1,731	$	-84,812

	Basic and diluted loss from continuing operations per unit			$	-0.39	$	-0.39
	Basic and diluted loss from discontinued operations per unit			$	-3.19	$	-3.19
	Basic and diluted loss per unit			$	-3.58	$	-3.58

Discontinued_Operations_Tables

Discontinued Operations (Tables)	12 Months Ended
Discontinued Operations (Tables)	Dec. 31, 2013
Discontinued Operations [Abstract]	'
Schedule Of Discontinued Operations	'
	The following amounts relating to the Robinson’s Bend Field assets have been reported as discontinued operations in the consolidated statements of operations in the years ending December 31, 2013 and 2012 (in thousands):



		Year Ending December 31,
		2013		2012
	Revenues	$	2,304	$	12,808
	Loss from discontinued operations	$	-2,686	$	-77,081
	The loss from discontinued operations for the year ended December 31, 2012 included an impairment charge of approximately $73.3 million to impair the asset group that contained our natural gas properties and inventory in the Robinson’s Bend Field. This impairment was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by the cash offer to purchase the assets for $63.0 million, subject to certain post-closing adjustments.
	See Note 1 for information regarding earnings per unit, including earnings per unit data relating to income from discontinued operations, which includes loss on sale of discontinued operations in 2013.
	The following table provides the major classes of assets and liabilities components of discontinued operations as of December 31, 2013 and 2012 (in thousands):



		December 31,
		2013		2012
	Accounts receivable	$	-	$	1,763
	Natural gas properties, net	$	-	$	67,301
	Total discontinued assets	$	-	$	69,259

	Accounts payable	$	-	$	711
	Accrued liabilities	$	-	$	771
	Asset retirement obligation	$	-	$	7,692
	Total discontinued liabilities	$	-	$	9,270

Acquisition_Tables

Acquisition (Tables)	12 Months Ended
Acquisition (Tables)	Dec. 31, 2013
Acquisition [Abstract]	'
Estimated Values Of Assets Acquired	'

	Oil and natural gas properties, equipment and facilities		$	31,497
	Asset retirement obligation			-1,088
	Net assets acquired		$	30,409


Revenues And Lease Operating Expenses	'


		Three Months Ended					Twelve Months Ended
		December 31,					December 31,
		2013			2012		2013		2012
	Revenue	$	3,018		$	5,036	$	15,782	$	20,939
	Lease Operating Expenses	$	819		$	997	$	3,047	$	4,049


Supplemental Pro Forma Information	'


		Pro Forma					Pro Forma
		Three Months Ended					Twelve Months Ended
		December 31,					December 31,
	(In thousands)	2013			2012		2013		2012
	Revenue	$	11,458		$	18,473	$	56,841	$	67,466
	Income (loss) from continuing operations	$	-13,066		$	1,093	$	-18,514	$	3,825
	Discontinued operations	$	-		$	-74,055	$	-2,686	$	-77,081
	Net Loss	$	-13,066		$	-72,962	$	-21,200	$	-73,256
	Income (loss) from continuing operations per unit
	Class A units - Basic and diluted	$	-0.16		$	0.01	$	-0.23	$	0.05
	Class B units - Basic and diluted	$	-0.46		$	0.04	$	-0.65	$	0.13
	Discontinued operations per unit
	Class A units - Basic and diluted	$	-		$	-0.92	$	-0.03	$	-0.96
	Class B units - Basic and diluted	$	-		$	-2.55	$	-0.09	$	-2.66
	Net loss per unit
	Class A units - Basic and diluted	$	-0.16		$	-0.9	$	-0.26	$	-0.91
	Class B units - Basic and diluted	$	-0.45		$	-2.52	$	-0.74	$	-2.53
	Weighted average units outstanding
	Class A units - Basic and diluted		1,615,017			1,613,924		1,615,103		1,614,076
	Class B units - Basic and diluted		28,457,577			28,412,032		28,057,592		28,412,353

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
Fair Value Measurements (Tables)	Dec. 31, 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 December 31, 2013 (in thousands):



		Fair Value Measurements at December 31, 2013
		Quoted Prices in		Significant other
		Active Markets for		Observable		Significant
		Identical Assets		Inputs		Unobservable Inputs		Netting Cash and		Fair Value at
		(Level 1)		(Level 2)		(Level 3)		Collateral		31-Dec-13
	Risk Mgmt Assets	$	—	$	11,577	$	—	$	-975	$	10,602
	Risk Mgmt Liabilities		—		-975		—		975		—
	Total Net Assets and Liabilities	$	—	$	10,602	$	—	$	—	$	10,602
	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)	12 Months Ended
Derivative And Financial Instruments (Tables)	Dec. 31, 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
	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	1,215,420		$	4.25		1,153,487		$	4.25	1,096,023	$	4.26	1,050,219	$	4.26	4,515,149	$	4.26
	2016	1,010,633		$	4.21		967,290		$	4.21	923,541	$	4.21	893,568	$	4.22	3,795,032	$	4.21
																	14,697,681
	MTM Fixed Price Basis Swaps – Enable Gas Transmission, LLC (East), ONEOK Gas Transportation (Oklahoma) or Southern Star Central Gas Pipeline (Texas, Oklahoma and Kansas)



		For the quarter ended (in MMBtu)
		March 31,					June 30,				September 30,			December 31,			Total
				Weighted					Weighted			Weighted			Weighted			Weighted
		Volume		Average $			Volume		Average $		Volume	Average $		Volume	Average $		Volume	Average $
	2014	1,178,422		$	0.39		1,133,022		$	0.39	1,084,270	$	0.39	1,047,963	$	0.39	4,443,677	$	0.39
																	4,443,677
	MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI)



		For the quarter ended (in Bbls)
		March 31,					June 30,				September 30,			December 31,			Total
				Average					Average			Average			Average			Average
		Volume		Price			Volume		Price		Volume	Price		Volume	Price		Volume	Price
	2014	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
																	464,406


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		31-Dec-13			31-Dec-12

	Commodity – MTM		Risk management assets - current		$	10,043		$	19,005
	Commodity – MTM		Risk management assets - non-current			1,534			12,025
			Total gross assets			11,577			31,030

	Commodity – MTM		Risk management assets – current			-903			-1,040
	Commodity – MTM		Risk management assets – non-current			-72			-946
	Commodity – MTM		Risk 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			-975			-6,794
			Total net assets and liabilities		$	10,602		$	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 Year Ended December 31,
	Derivative Type		in Income		2013			2012

	Commodity – MTM		Oil and natural gas sales		$	-1,486		$	15,701
	Interest Rate – MTM		Interest expense			-65			-1,061
			Total		$	-1,551		$	14,640










					Amount of Gain/(Loss) Reclassified from
			Location of Gain/(Loss) for		AOCI into Income – Effective
			Effective and Ineffective		For the Three Months Ended December 31,
	Derivative Type		Portion of Derivative in Income		2013			2012

	Commodity – Cash Flow		Natural gas sales		$	—		$	1,271
			Total		$	—		$	1,271

Oil_And_Natural_Gas_Properties1

Oil And Natural Gas Properties (Tables)	12 Months Ended
Oil And Natural Gas Properties (Tables)	Dec. 31, 2013
Oil And Natural Gas Properties [Abstract]	'
Oil and Natural Gas Properties	'


		December 31,
		2013		2012
	Oil and natural gas properties and related equipment
	(successful efforts method)
	Property (acreage) costs
	Proved property	$	636,816	$	591,889
	Unproved property		1,589		1,380
	Total property costs		638,405		593,269
	Materials and supplies		1,054		771
	Land		751		751
	Total		640,210		594,791
	Less: Accumulated depreciation, depletion, amortization and impairments		-495,215		-474,669
	Oil and natural gas properties and equipment, net	$	144,995	$	120,122


Depletion, Depreciation, Amortization and Impairments	'


		Year Ended December 31,
		2013		2012

	DD&A of oil and natural gas-related assets	$	18,972	$	11,732
	Asset Impairments		2,357		109
	Total	$	21,329	$	11,841

Asset_Retirement_Obligation_Ta

Asset Retirement Obligation (Tables)	12 Months Ended
Asset Retirement Obligation (Tables)	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Reconciliation of Asset Retirement Obligation	'


		December 31,
		2013		2012
	Asset retirement obligation, beginning balance	$	7,665	$	7,052
	Liabilities added from acquisitions		1,088		-
	Liabilities added from drilling		244		162
	Settlements		-3		-8
	Accretion expense		519		459
	Asset retirement obligation, ending balance	$	9,513	$	7,665

UnitBased_Compensation_Tables

Unit-Based Compensation (Tables)	12 Months Ended
Unit-Based Compensation (Tables)	Dec. 31, 2013
2009 Omnibus Incentive Compensation Plan [Member]	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Schedule Of Units Granted	'


			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit

	Outstanding at December 31, 2011	962,281	$	3.41
	Vested	-215,308		3.40
	Granted	7,190		1.32
	Returned/Cancelled	-87,385		3.40
	Outstanding at December 31, 2012	666,778		3.39
	Vested	-370,363		2.66
	Granted	184,313		1.27
	Returned/Cancelled	-144,177		2.77
	Outstanding at December 31, 2013	336,551	$	3.29


Long Term Incentive Plan [Member]	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'
Schedule Of Units Granted	'


			Weighted
			Average
		Number of	Grant Date
		Restricted	Fair Value
		Units	Per Unit

	Outstanding at December 31, 2011	149,869	$	3.44
	Vested	-56,025		3.42
	Granted	30,000		2.17
	Returned/Cancelled	-28,930		3.42
	Outstanding at December 31, 2012	94,914		3.05
	Vested	-61,273		2.24
	Granted	38,023		1.17
	Returned/Cancelled	-27,888		2.56
	Outstanding at December 31, 2013	43,776	$	2.87

Supplemental_Information_On_Oi1

Supplemental Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]	'
Schedule Of Capitalized Costs	'



		December 31,
		2013			2012
	Capitalized costs at the end of the period:⁽ᵃ⁾
	Oil and natrual gas properties and related equipment (successful efforts method)
	Property costs
	Proved property	$	636,816		$	591,889
	Unproved property		1,589			1,380
	Total property costs		638,405			593,269
	Materials and supplies		1,054			771
	Land		751			751
	Total		640,210			594,791
	Less: Accumulated depreciation, depletion, amortization and impairments		-495,215			-474,669
	Oil and natural gas properties and equipment, net	$	144,995		$	120,122

	(a)Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.

Schedule Of Costs Incurred For Oil And Natural Gas Producing Activities	'


		For the year ended December 31,
		2013			2012
	Costs incurred for the period:
	Acquisition of properties
	Proved	$	20,012		$	75
	Unproved		209			177
	Development costs		15,694			15,336
	Oil and natural gas properties and equipment, net	$	35,915		$	15,588


Schedule Of Changes In Proved Developed And Undeveloped Reserves	'




		For the year ended December 31,
		2013		2012
	(In Mmcfe)
	Beginning balance	92,982		201,330
	Extensions and discoveries	4,825		2,049
	Purchases of reserves in place	7,150		-
	Sales of reserves in place	-49,385		-256
	Revisions of previous estimates	44,727		-97,178
	Production	-9,045		-12,963
	Ending balance	91,254		92,982

	Ending balance from continuing operations	91,254		43,596
	Ending balance from discontinued operations⁽ᵃ⁾	-		49,386
	Total ending balance	91,254		92,982

	Proved developed reserves from continuing operations	78,629		40,867
	Proved developed reserves from discontinued operations	-		49,134
	Total proved developed reserves	78,629		90,001

	Proved undeveloped reserves from continuing operations	12,625		2,729
	Proved undeveloped reserves from discontinued operations	-		252
	Total proved undeveloped reserves	12,625		2,981
	⁽ᵃ⁾ In February 2013, we sold all of our Black Warrior Basin properties.

Summary Of Standardized Measure Of Estimated Discounted Future Cash Flows From Properties	'


			For the year ended December 31,
			2013			2012
	Future cash inflows		$	502,831		$	360,825
	Future production costs			-227,315			-194,198
	Future estimated development costs			-40,694			-11,124
	Future net cash flows			234,822			155,503
	10% annual discount for estimated timing of cash flows			-91,108			-65,834
	Standardized measure of discounted estimated future net cash
		flows related to proved gas reserves	$	143,714		$	89,669

	Standardized measure from continuing operations			143,714			60,455
	Standardized measure from discontinued operations⁽ᵃ⁾			-			29,214
	Standardized measure of discounted estimated future net cash
		flows related to proved gas reserves	$	143,714		$	89,669
	⁽ᵃ⁾ In February 2013, we sold all of our Black Warrior Basin properties.

Summary Of Change In Standardized Measure Of Estimated Discounted Future Net Cash Flows	'


			For the year ended December 31,
			2013			2012
	Beginning of the period		$	89,669		$	160,691
	Sales and transfers of oil and natural gas, net of production costs			-21,244			-39,699
	Net changes in prices and production costs related to future production			50,425			-19,228
	Development costs incurred during the period			5,615			18,818
	Changes in extensions and discoveries			28,494			12,590
	Revisions of previous quantity estimates			21,455			-83,750
	Sales of reserves in place			-2,297			-1,476
	Accretion discount			8,967			16,069
	Other			-37,370			25,654
	Standardized measure of discounted future net cash flows related to
		proved gas reserves	$	143,714		$	89,669

	Standardized measure from continuing operations			143,714			60,455
	Standardized measure from discontinued operations⁽ᵃ⁾			-			29,214
	Standardized measure of discounted future net cash flows related to
		proved gas reserves	$	143,714		$	89,669
	⁽ᵃ⁾ In February 2013, we sold all of our Black Warrior Basin properties.

Recovered_Sheet1

Summary of Significant Accounting Policies (Narrative) (Details) (USD $)

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Aug. 09, 2013

Dec. 31, 2013

Aug. 09, 2013

Dec. 31, 2013

customer

Common Class B [Member]

Constellation Energy Partners Management [Member]

Maximum [Member]

Checks-In-Transit [Member]

Sales [Member]

Sanchez Energy Partners I [Member]

Common Class A [Member]

Common Class B [Member]

customer

CEP Services Company [Member]

Customer One [Member]

Customer Two [Member]

Customer Three [Member]

Customer Four [Member]

Customer Five [Member]

Common Class A [Member]

Common Class B [Member]

Significant Accounting Policies [Line Items]

Units owned by third party

484,505

5,918,894

1,130,512

4,724,407

Units owned by third party, percentage of total shares

30.00%

70.00%

16.60%

Accounts payable

$12,000

$480,000

$600,000

Restricted cash

1,748,000

600,000

Number of large customers

Allowance for doubtful accounts

100,000

Percentage of sales revenue

22.00%

28.00%

20.00%

10.00%

17.00%

9.00%

14.00%

9.00%

8.00%

Federal and state tax liability

100,000

Deferred assets

Deferred liabilities

Restricted unvested common units granted and outstanding

380,327

Summary_Of_Significant_Account3

Summary Of Significant Accounting Policies (Schedule Of Weighted Average Units Outstanding) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Class Of Stock [Line Items]	'	'
Weighted average units outstanding - Basic and Diluted	26,143,719	24,171,510
Common Class A [Member]	'	'
Class Of Stock [Line Items]	'	'
Weighted average units outstanding - Basic and Diluted	933,613	483,564
Common Class B [Member]	'	'
Class Of Stock [Line Items]	'	'
Weighted average units outstanding - Basic and Diluted	25,210,106	23,687,946

Summary_Of_Significant_Account4

Summary Of Significant Accounting Policies (Earnings Per Common Unit Amounts) (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Class Of Stock [Line Items]	'	'
Loss from continuing operations	($25,857)	($9,462)
Distributions	'	'
Loss from continuing operations	-25,857	-9,462
Discontinued operations	-2,686	-77,081
Net loss	-28,543	-86,543
Common Class A [Member]	'	'
Class Of Stock [Line Items]	'	'
Distributions	'	'
Loss from continuing operations	-517	-189
Discontinued operations	-54	-1,542
Net loss	-571	-1,731
Basic and diluted loss from continuing operations per unit	($0.55)	($0.39)
Basic and diluted loss from discontinued operations per unit	($0.06)	($3.19)
Basic and diluted loss per unit	($0.61)	($3.58)
Common Class B [Member]	'	'
Class Of Stock [Line Items]	'	'
Distributions	'	'
Loss from continuing operations	-25,340	-9,273
Discontinued operations	-2,632	-75,539
Net loss	($27,972)	($84,812)
Basic and diluted loss from continuing operations per unit	($1.01)	($0.39)
Basic and diluted loss from discontinued operations per unit	($0.10)	($3.19)
Basic and diluted loss per unit	($1.11)	($3.58)

Discontinued_Operations_Narrat

Discontinued Operations (Narrative) (Details) (USD $)	12 Months Ended		0 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Feb. 28, 2013	Mar. 31, 2013	Dec. 31, 2012
	Dec. 31, 2013	Dec. 31, 2012	Robinson's Bend Field [Member]	Robinson's Bend Field [Member]	Robinson's Bend Field [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'
Proceeds from sale of business	'	'	$63,000,000	'	'
Closing adjustment	'	'	4,000,000	'	'
Gain (Loss) on sale	'	'	'	-3,100,000	'
Asset Impairments	$2,357,000	$109,000	'	'	$73,300,000

Discontinued_Operations_Schedu

Discontinued Operations (Schedule Of Discontinued Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Discontinued Operations [Abstract]	'	'
Revenues	$2,304	$12,808
Loss from discontinued operations	($2,686)	($77,081)

Discontinued_Operations_Schedu1

Discontinued Operations (Schedule Of Major Classes Of Assets And Liabilities Components Of Discontinued Operations) (Details) (USD $)	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2012
Discontinued Operations [Abstract]	'
Accounts receivable	$1,763
Natural gas properties, net	67,301
Total discontinued assets	69,259
Accounts payable	711
Accured liabilities	771
Asset retirement obligation	7,692
Total discontinued liabilities	$9,270

Acquisition_Narrative_Details

Acquisition (Narrative) (Details) (USD $)	12 Months Ended		0 Months Ended		12 Months Ended	0 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Aug. 09, 2013	Aug. 09, 2013	Dec. 31, 2013	Aug. 09, 2013	Dec. 31, 2013
			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]
			item	Common Class A [Member]	Common Class A [Member]	Common Class B [Member]	Common Class B [Member]
Business Acquisition [Line Items]	'	'	'	'	'	'	'
Purchase price for acquisition	'	'	$30,400,000	'	'	'	'
Cash consideration paid	20,221,000	252,000	20,100,000	'	'	'	'
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	'	'	$16,700,000	'	'	'	'
Number of wells acquired	'	'	67	'	'	'	'

Acquisition_Estimated_Values_O

Acquisition (Estimated Values Of Assets Acquired) (Details) (USD $)	Dec. 31, 2013	Aug. 01, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Aug. 01, 2013	Dec. 31, 2012
Acquisition [Abstract]	'	'	'
Oil and natural gas properties, equipment and facilities	$639,156	$31,497	$594,020
Asset retirement obligation	-9,513	-1,088	-7,665
Net assets acquired	'	$30,409	'

Acquisition_Revenues_And_Lease

Acquisition (Revenues And Lease Operating Expenses) (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]	'	'	'	'
Revenues	'	'	$44,077	$46,527
Lease Operating Expenses	'	'	18,858	19,411
Sanchez Energy Partners I [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Revenues	3,018	5,036	15,782	20,939
Lease Operating Expenses	$819	$997	$3,047	$4,049

Acquisition_Supplemental_Pro_F

Acquisition (Supplemental Pro Forma Information) (Details) (Sanchez Energy Partners I [Member], USD $)	3 Months Ended		12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]	'	'	'	'
Revenue	$11,458	$18,473	$56,841	$67,466
Income (loss) from continuing operations	-13,066	1,093	-18,514	3,825
Discontinued operations	'	-74,055	-2,686	-77,081
Net Loss	($13,066)	($72,962)	($21,200)	($73,256)
Common Class A [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Income (loss) from continuing operations per unit - Basic and diluted	($0.16)	$0.01	($0.23)	$0.05
Discontinued operations per unit - Basic and diluted	'	($0.92)	($0.03)	($0.96)
Net loss per unit - Basic and diluted	($0.16)	($0.90)	($0.26)	($0.91)
Weighted average units outstanding - Basic and diluted	1,615,017	1,613,924	1,615,103	1,614,076
Common Class B [Member]	'	'	'	'
Business Acquisition [Line Items]	'	'	'	'
Income (loss) from continuing operations per unit - Basic and diluted	($0.46)	$0.04	($0.65)	$0.13
Discontinued operations per unit - Basic and diluted	'	($2.55)	($0.09)	($2.66)
Net loss per unit - Basic and diluted	($0.45)	($2.52)	($0.74)	($2.53)
Weighted average units outstanding - Basic and diluted	28,457,577	28,412,032	28,057,592	28,412,353

Fair_Value_Measurements_Fair_V

Fair Value Measurements (Fair Value Of Assets And Liabilities On A Recurring Basis) (Details) (Recurring, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	$10,602	$25,396
Risk Mgmt Liabilities	'	-1,160
Total Net Assets and Liabilities	10,602	24,236
Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	11,577	31,030
Risk Mgmt Liabilities	-975	-6,794
Total Net Assets and Liabilities	10,602	24,236
Netting Cash And Collateral [Member]	'	'
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]	'	'
Risk Mgmt Assets	-975	-5,634
Risk Mgmt Liabilities	$975	$5,634

Derivative_And_Financial_Instr2

Derivative And Financial Instruments (Narrative) (Details) (USD $)	1 Months Ended		3 Months Ended
In Millions, unless otherwise specified	31-May-13	Mar. 31, 2013	Mar. 31, 2013	Dec. 31, 2013
	31-May-13	Mar. 31, 2013	bbl	item
Derivative [Line Items]	'	'	'	'
Number of counterparties	'	'	'	2
Percentage of hedge of anticipated production volume, 2015	'	'	'	100.00%
Percentage of hedge of anticipated production volume, 2016	'	'	'	100.00%
Cost to liquidate derivative hedge	'	'	$0.30	'
Number of barrels of oil	'	'	58,157	'
Execution of amendment	'	'	0.2	'
Reduction in outstanding interest rate swaps	'	30	30	'
Increase in interest rate swap settlement	'	2.1	'	'
Increase in natrual gas settlement	$0.30	'	'	'
Swaps Covering 2013 NYMEX	'	'	'	'
Derivative [Line Items]	'	'	'	'
Derivative swaps liquidated	'	'	395,218	'
Amount reduced from outstanding swap positions	'	'	1,041,814	'
Derivative contract swap, fixed price	'	3.66	3.66	'
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)

3 Months Ended

12 Months Ended

3 Months Ended

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Jun. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

bbl

NYMEX 2014 [Member]

NYMEX 2015 [Member]

NYMEX 2016 [Member]

NYMEX [Member]

Centerpoint, ONEOK, Or Southern Star 2014 [Member]

Centerpoint, ONEOK, Or Southern Star [Member]

West Texas Intermediate 2014 [Member]

West Texas Intermediate 2015 [Member]

West Texas Intermediate 2016 [Member]

West Texas Intermediate [Member]

First Quarter [Member]

Second Quarter [Member]

Third Quarter [Member]

Fourth Quarter [Member]

MMBTU

bbl

NYMEX 2014 [Member]

NYMEX 2015 [Member]

NYMEX 2016 [Member]

Centerpoint, ONEOK, Or Southern Star 2014 [Member]

West Texas Intermediate 2014 [Member]

West Texas Intermediate 2015 [Member]

West Texas Intermediate 2016 [Member]

NYMEX 2014 [Member]

NYMEX 2015 [Member]

NYMEX 2016 [Member]

Centerpoint, ONEOK, Or Southern Star 2014 [Member]

West Texas Intermediate 2014 [Member]

West Texas Intermediate 2015 [Member]

West Texas Intermediate 2016 [Member]

NYMEX 2014 [Member]

NYMEX 2015 [Member]

NYMEX 2016 [Member]

Centerpoint, ONEOK, Or Southern Star 2014 [Member]

West Texas Intermediate 2014 [Member]

West Texas Intermediate 2015 [Member]

West Texas Intermediate 2016 [Member]

NYMEX 2014 [Member]

NYMEX 2015 [Member]

NYMEX 2016 [Member]

Centerpoint, ONEOK, Or Southern Star 2014 [Member]

West Texas Intermediate 2014 [Member]

West Texas Intermediate 2015 [Member]

West Texas Intermediate 2016 [Member]

MMBTU

bbl

MMBTU

bbl

MMBTU

bbl

MMBTU

bbl

Derivatives, Fair Value [Line Items]

Volume (in MMBtu)

6,387,500

4,515,149

3,795,032

14,697,681

4,443,677

1,575,000

1,215,420

1,010,633

1,178,422

1,592,500

1,153,487

967,290

1,133,022

1,610,000

1,096,023

923,541

1,084,270

1,610,000

1,050,219

893,568

1,047,963

Volume (in Bbls)

58,157

222,476

175,813

66,117

464,406

60,928

47,747

17,957

57,154

45,065

16,985

53,797

42,672

16,048

50,597

40,329

15,127

Average Price

5.75

4.26

4.21

0.39

94.7

91.02

85.5

5.75

4.25

4.21

0.39

94.64

90.95

85.5

5.75

4.25

4.21

0.39

94.67

85.5

5.75

4.26

4.21

0.39

94.72

91.04

85.5

5.75

4.26

4.22

0.39

94.8

91.1

85.5

Derivative_And_Financial_Instr4

Derivative And Financial Instruments (Fair Value for Risk Management Assets and Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-current	$9,141	$17,965
Risk management assets-non-current	1,461	7,431
Total gross assets	11,577	31,030
Risk management liabilities-current	'	-523
Risk management liabilities-non-current	'	-637
Total gross liabilities	-975	-6,794
Total net assets and liabilities	10,602	24,236
Risk Management Commodity [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
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 assets-current	10,043	19,005
Risk management liabilities-current	-903	-1,040
Noncurrent Assets [Member] \| Risk Management Commodity [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-non-current	1,534	12,025
Risk management liabilities-non-current	-72	-946
Noncurrent Assets [Member] \| Risk Management Interest Rate [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Risk management assets-non-current	'	($3,648)

Derivative_And_Financial_Instr5

Derivative And Financial Instruments (Fair Value Applicable to Income Statement) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivative gains (losses) recognized in income	($1,551)	$14,640
Oil And Liquids Sales [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivative gains (losses) recognized in income	-1,486	15,701
Interest Expense [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Derivative gains (losses) recognized in income	($65)	($1,061)

Derivative_And_Financial_Instr6

Derivative And Financial Instruments (Fair Value Disclosures Applicable to Income Statement Reclassified) (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'
Amount of gain/ (loss) Reclassified from AOCI Income	'	$1,271
Commodity - Cash Flow [Member] \| Natural Gas Sales [Member]	'	'
Derivative Instruments and Hedging Activities Disclosures [Line Items]	'	'
Amount of gain/ (loss) Reclassified from AOCI Income	'	$1,271

Debt_Details

Debt (Details) (USD $)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

31-May-13

Apr. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Societe Generale [Member]

OneWest Bank [Member]

Bank of Oklahoma [Member]

Letter of Credit [Member]

Reserve Based Credit Facility [Member]

Minimum [Member]

Maximum [Member]

London Interbank Offered Rate (LIBOR) [Member]

ABR [Member]

London Interbank Offered Rate (LIBOR) [Member]

ABR [Member]

Line of Credit Facility [Line Items]

Reserve based credit facility maximum borrowing capacity

$350,000,000

$20,000,000

Maturity date of reserve-based credit facility

30-May-17

Borrowing base amount

55,000,000

37,500,000

55,000,000

Amount borrowed under credit facility

50,700,000

84,000,000

Commitment fee percentage

36.36%

27.28%

Interest rate

2.50%

1.50%

3.50%

2.50%

Commitment fee on unutilized borrowing base

0.50%

Outstanding debt on our reserve based credit facility

50,700,000

Total net debt adjusted to EBITDA

350.00%

Cash interest expense adjusted to EBITDA

250.00%

Consolidated current asset ratio

100.00%

Ownership percentage by subsidiary

20.00%

Ownership percentage by person or group of persons

35.00%

Exceeding of reserve-based credit facility over borrowing base

90.00%

Hedging of projected monthly production

115.00%

Heding of interest rate

90.00%

Remaining borrowing capacity

4,300,000

Actual debt ratio

260.00%

Required debt ratio

350.00%

Actual working capital ratio

130.00%

Required working capital ratio

100.00%

Actual interest coverage ratio

930.00%

Required interest coverage ratio

250.00%

Outstanding debt under reserve-based credit facility

50,700,000

34,000,000

Unamortized debt issue costs

$800,000

$1,200,000

Recovered_Sheet2

Oil and Natural Gas Properties (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]	'	'
Asset Impairments	$2,357,000	$109,000
Proceeds from sale of trucks and equipment	58,987,000	1,508,000
Exploration costs	0	0
Trucks And Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Proceeds from sale of trucks and equipment	'	100,000
Gain (Loss) from sale of assets	'	0
Equipment, Furniture and Fixtures [Member] \| Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Useful life	'1 year	'
Equipment, Furniture and Fixtures [Member] \| Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Useful life	'7 years	'
Buildings	'	'
Property, Plant and Equipment [Line Items]	'	'
Useful life	'20 years	'
Pipeline and Gathering Systems [Member] \| Minimum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Useful life	'25 years	'
Pipeline and Gathering Systems [Member] \| Maximum [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Useful life	'40 years	'
Texas And Louisiana Oil And Natural Gas Fields [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Non-cash impairment charges	2,100,000	'
Woodford Shale	'	'
Property, Plant and Equipment [Line Items]	'	'
Non-cash impairment charges	200,000	100,000
Kansas And Nebraska Oil Wells [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Number of gross non-operated oil wells sold	'	14
Proceed from sale of interest of non-operated oil wells	'	$1,400,000

Recovered_Sheet3

Oil and Natural Gas Properties (Oil and Natural Gas Properties) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Oil And Natural Gas Properties [Abstract]	'	'
Proved property	$636,816	$591,889
Unproved property	1,589	1,380
Total property costs	638,405	593,269
Materials and supplies	1,054	771
Land	751	751
Total	640,210	594,791
Less: Accumulated depreciation, depletion, amortization and impairments	-495,215	-474,669
Oil and natural gas properties and equipment, net	$144,995	$120,122

Oil_And_Natural_Gas_Properties2

Oil And Natural Gas Properties (Depletion, Depreciation, Amortization and Impairments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Oil And Natural Gas Properties [Abstract]	'	'
DD&A of oil and natural gas-related assets	$18,972	$11,732
Asset Impairments	2,357	109
Total	$21,329	$11,841

Benefit_Plans_Details

Benefit Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Benefit Plans [Abstract]	'	'
Matching contributions made by employer	$0.30	$0.50

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)

1 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Jun. 30, 2011

Dec. 31, 2013

Aug. 09, 2013

Dec. 31, 2013

Aug. 09, 2013

Dec. 31, 2013

Jun. 30, 2011

Dec. 31, 2013

item

PostRock [Member]

Sanchez Oil And Gas Corporation [Member]

Common Class A [Member]

Common Class B [Member]

Sanchez Energy Partners I [Member]

NPI [Member]

Maximum [Member]

Constellation Energy Partners Management [Member]

Common Class A [Member]

Common Class B [Member]

Related Party Transaction [Line Items]

Units owned by third party

484,505

5,918,894

1,130,512

4,724,407

Units owned by third party, percentage of total shares

30.00%

70.00%

16.60%

Ownership percentage in company by related party

21.30%

19.50%

Percentage of outstanding common units owned by interest unitholder

15.00%

Voting percentage of Class B common units

66.66%

Percentage of quarterly dividends represented by Class C interestes helf by CPEH

15.00%

Contributions from CHI

Number of distributions

Distribution period

'6 years

Legal fee reimbursement

1.2

Purchase price for acquisition

30.4

Impairment recognzied upon NPI acquisition

Maximum interest upon liquidation

$6.70

Commitments_And_Contingencies_

Commitments And Contingencies (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified	Dec. 31, 2013
Commitments And Contingencies [Abstract]	'
Accrued liability	$5.90

Asset_Retirement_Obligation_Na

Asset Retirement Obligation (Narrative) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation [Abstract]	'	'	'
Legally restricted assets	$0	$0	$0

Asset_Retirement_Obligation_Re

Asset Retirement Obligation (Reconciliation of Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation [Abstract]	'	'
Asset retirement obligation, beginning balance	$7,665	$7,052
Liabilities added from acquisition	1,088	'
Liabilities added from drilling	-244	-162
Settlements	-3	-8
Accretion expense	519	459
Asset retirement obligation, ending balance	$9,513	$7,665

UnitBased_Compensation_Narrati

Unit-Based Compensation (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Unit-Based Compensation [Abstract]	'	'
Non-cash compensation expense	$1	$1.50
Unrecognized portion of share based compensation expense	$0.50	'

UnitBased_Compensation_Schedul

Unit-Based Compensation (Schedule Of Units Granted) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
2009 Omnibus Incentive Compensation Plan [Member]	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Number of Restricted Units, Vested	-1,030,115	-659,752
Number of Restricted Units, Granted	1,366,666	1,326,530
Number of Restricted Units, Outstanding	336,551	'
Long Term Incentive Plan [Member]	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Number of Restricted Units, Vested	-302,958	-241,685
Number of Restricted Units, Granted	346,734	336,599
Number of Restricted Units, Outstanding	43,776	'
Restricted Stock Units (RSUs) [Member] \| 2009 Omnibus Incentive Compensation Plan [Member]	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Number of Restricted Units, Outstanding	666,778	962,281
Number of Restricted Units, Vested	-370,363	-215,308
Number of Restricted Units, Granted	184,313	7,190
Number of Restricted Units, Returned/Cancelled	-144,177	-87,385
Number of Restricted Units, Outstanding	336,551	666,778
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	3.39	3.41
Weighted Averaged Grant Date Fair Value Per Unit, Vested	2.66	3.4
Weighted Averaged Grant Date Fair Value Per Unit, Granted	1.27	1.32
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled	2.77	3.4
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	3.29	3.39
Restricted Stock Units (RSUs) [Member] \| Long Term Incentive Plan [Member]	'	'
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]	'	'
Number of Restricted Units, Outstanding	94,914	149,869
Number of Restricted Units, Vested	-61,273	-56,025
Number of Restricted Units, Granted	38,023	30,000
Number of Restricted Units, Returned/Cancelled	-27,888	-28,930
Number of Restricted Units, Outstanding	43,776	94,914
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	3.05	3.44
Weighted Averaged Grant Date Fair Value Per Unit, Vested	2.24	3.42
Weighted Averaged Grant Date Fair Value Per Unit, Granted	1.17	2.17
Weighted Averaged Grant Date Fair Value Per Unit, Reutrned/Cancelled	2.56	3.42
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	2.87	3.05

Distributions_To_Unitholders_D

Distributions To Unitholders (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Distributions To Unitholders [Abstract]	'	'
Available cash balance	$0	$0

Members_Equity_Details

Members' Equity (Details) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Common units tendered for tax withholding purpose	139,810	90,425
Units tendered by employees for tax withholding, cost	$185	$200
Long Term Incentive Plan [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Shares units outstanding	'	94,914
Unvested restricted common stock issued	43,776	'
Common units granted	346,734	336,599
Common units available under incentive plan	450,000	450,000
Common units vested	302,958	241,685
Additional units granted	'	76,046
Additional units vested	'	38,023
2009 Omnibus Incentive Compensation Plan [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Shares units outstanding	'	666,778
Unvested restricted common stock issued	336,551	'
Common units granted	1,366,666	1,326,530
Common units available under incentive plan	1,650,000	1,650,000
Common units vested	1,030,115	659,752
Additional units granted	'	323,194
Additional units vested	'	161,597
Common Class A [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Shares units outstanding	1,615,017	483,418
Common Class B [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Shares units outstanding	28,462,185	23,687,507

Supplemental_Information_On_Oi2

Supplemental Information On Oil And Natural Gas Producing Activities (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Mcfe	Mcfe	Mcfe
Reserve Quantities [Line Items]	'	'	'
Exploration costs	$0	$0	'
Proved reserve estimates	91,254,000	92,982,000	201,330,000
Reserve revision	78,629,000	90,001,000	'
Increase (decrease) in proved reserve estimates	-1,700,000	-108,300,000	'
Actual production amount	'	12,600,000	'
Increase in production	'	3,800,000	'
Oil [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Weighted-average product price	97.89	'	'
Natural Gas Liquids [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Weighted-average product price	41.21	'	'
Natural Gas [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Percentage of reserves	85.00%	93.00%	'
Weighted-average product price	3.706	'	'
Cherokee Basin [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Increase (decrease) in proved reserve estimates	4,800,000	'	'
SEC-required price used to prepare reserve report	'	2,910,000	'
Increase (decrease) in price used to determine reserve report	'	-970,000	'
Black Warrior Basin [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Reserve revision	44,800,000	97,200,000	'
Increase (decrease) in proved reserve estimates	-49,000,000	'	'
SEC-required price used to prepare reserve report	'	2,850,000	'
Increase (decrease) in price used to determine reserve report	'	-1,350,000	'
Black Warrior Basin [Member] \| Oil [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Increase (decrease) in proved reserve estimates	'	2,000,000	'
Black Warrior Basin [Member] \| Natural Gas [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Increase (decrease) in proved reserve estimates	'	200,000	'
Sanchez Energy Partners I [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Increase (decrease) in proved reserve estimates	7,000,000	'	'

Supplemental_Information_On_Oi3

Supplemental Information On Oil And Natural Gas Producing Activities (Schedule Of Capitalized Costs) (Details) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]	'		'
Proved property	$636,816	[1]	$591,889	[1]
Unproved property	1,589	[1]	1,380	[1]
Total property costs	638,405	[1]	593,269	[1]
Materials and supplies	1,054	[1]	771	[1]
Land	751	[1]	751	[1]
Total	640,210	[1]	594,791	[1]
Less: accumulated depreciation, depletion, amortization and impairments	-495,215	[1]	-474,669	[1]
Oil and natural gas properties and equipment, net	$144,995	[1]	$120,122	[1]

[1]	Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.

Supplemental_Information_On_Oi4

Supplemental Information On Oil And Natural Gas Producing Activities (Schedule Of Costs Incurred For Oil And Natural Gas Producing Activities) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]	'	'
Proved	$20,012	$75
Unproved	209	177
Development costs	15,694	15,336
Oil and natural gas properties and equipment, net	$35,915	$15,588

Supplemental_Information_On_Oi5

Supplemental Information On Oil And Natural Gas Producing Activities (Schedule Of Changes In Proved Developed And Undeveloped Reserves) (Details)	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011
	Mcfe	Mcfe		Mcfe
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]	'	'		'
Beginning balance	91,254,000	92,982,000		201,330,000
Extensions and discoveries	4,825,000	2,049,000		'
Purchases of reserves in place	7,150,000	'		'
Sales of reserves in place	-49,385,000	-256,000		'
Revisions of previous estimates	44,727,000	-97,178,000		'
Production	-9,045,000	-12,963,000		'
Ending balance	91,254,000	92,982,000		201,330,000
Ending balance from continuing operations	91,254,000	43,596,000		'
Ending balance from discontinued operations	'	49,386,000	[1]	'
Proved developed reserves from continuing operations	78,629,000	40,867,000		'
Proved developed reserves from discontinued operations	'	49,134,000		'
Total proved developed reserves	78,629,000	90,001,000		'
Proved undeveloped reserves from continuing operations	12,625,000	2,729,000		'
Proved undeveloped reserves from discontinued operations	'	252,000		'
Total proved undeveloped reserves	12,625,000	2,981,000		'

[1]	In February 2013, we sold all of our Black Warrior Basin properties.

Supplemental_Information_On_Oi6

Supplemental Information On Oil And Natural Gas Producing Activities (Summary Of Standardized Measure Of Estimated Discounted Future Cash Flows From Properties) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]	'	'
Future cash inflows	$502,831	$360,825
Future production costs	-227,315	-194,198
Future estimated development costs	-40,694	-11,124
Future net cash flows	234,822	155,503
10% annual discount for estimated timing of cash flows	-91,108	-65,834
Standardized measure of discounted estimated future net cash flows related to proved gas reserves	143,714	89,669
Standardized measure from continuing operations	143,714	60,455
Standardized measure from discontinued operations	'	$29,214	[1]

[1]	In February 2013, we sold all of our Black Warrior Basin properties.

Supplemental_Information_On_Oi7

Supplemental Information On Oil And Natural Gas Producing Activities (Summary Of Change In Standardized Measure Of Estimated Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Supplemental Information On Oil And Natural Gas Producing Activites [Abstract]	'	'
Beginning of the period	$89,669	$160,691
Sales and transfers of oil and natural gas, net of production costs	-21,244	-39,699
Net changes in prices and production costs related to future production	50,425	-19,228
Development costs incurred during the period	5,615	18,818
Changes in extensions and discoveries	28,494	12,590
Revisions of previous quantity estimates	21,455	-83,750
Sales of reserves in place	-2,297	-1,476
Accretion discount	8,967	16,069
Other	-37,370	25,654
Standardized measure of discount future net cash flows related to proved gas reserves	143,714	89,669
Standardized measure from continuing operations	143,714	60,455
Standardized measure from discontinued operations	'	$29,214	[1]

[1]	In February 2013, we sold all of our Black Warrior Basin properties.

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	12 Months Ended		1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2013
	Dec. 31, 2013	Dec. 31, 2012	Constellation Holdering, Inc. [Member]	Constellation Holdering, Inc. [Member]
Subsequent Event [Line Items]	'	'	'	'
Proceeds from sales of shares	'	'	$8,000,000	'
Quarterly dividend amount	'	'	'	$333,333.33
Dividend payment period	'	'	'	'6 years