New Source Energy Partners (NSLP) 10-Q/A 23 May 14 2014 Q1 Quarterly report (amended) Financial data

Document_And_Entity_Informatio

Document And Entity Information	3 Months Ended
	Mar. 31, 2014	1-May-14	1-May-14	1-May-14
		Common Units	Subordinated Units	General Partnership Units
Document Information [Line Items]	'	'	'	'
Entity Registrant Name	'New Source Energy Partners L.P.	'	'	'
Document Type	'10-Q	'	'	'
Current Fiscal Year End Date	'--12-31	'	'	'
Entity Common Stock, Shares Outstanding	'	13,538,245	2,205,000	155,102
Amendment Flag	'false	'	'	'
Entity Central Index Key	'0001560443	'	'	'
Entity Current Reporting Status	'Yes	'	'	'
Entity Voluntary Filers	'No	'	'	'
Entity Filer Category	'Non-accelerated Filer	'	'	'
Entity Well-known Seasoned Issuer	'No	'	'	'
Document Period End Date	31-Mar-14	'	'	'
Document Fiscal Year Focus	'2014	'	'	'
Document Fiscal Period Focus	'Q1	'	'	'

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Current assets:	'	'
Cash	$929,000	$7,291,000
Accounts receivable	18,161,000	12,609,000
Other current assets	987,000	1,114,000
Total current assets	20,077,000	21,014,000
Property and equipment, net	10,941,000	8,166,000
Oil and natural gas properties, at cost, using full cost method:	'	'
Proved oil and natural gas properties	321,599,000	291,829,000
Accumulated depreciation, depletion, and amortization	-134,781,000	-128,961,000
Total oil and natural gas properties, net	186,818,000	162,868,000
Prepaid drilling and completion costs	577,000	1,455,000
Intangible asset - customer relationships, net	31,918,000	35,009,000
Goodwill	23,974,000	23,974,000
Other assets	2,269,000	2,224,000
Total assets	276,574,000	254,710,000
Current liabilities:	'	'
Accounts payable	2,215,000	2,268,000
Accounts payable-related parties	10,286,000	8,221,000
Accrued liabilities	1,275,000	999,000
Factoring payable	0	1,907,000
Derivative obligations	3,450,000	3,167,000
Line of credit	2,148,000	0
Current portion of long-term debt	1,632,000	719,000
Total current liabilities	21,006,000	17,281,000
Contingent consideration payable to related parties	6,753,000	6,320,000
Long-term related party payables	350,000	350,000
Credit facility	90,000,000	78,500,000
Long-term debt, net of current portion	2,910,000	1,514,000
Derivative obligations	356,000	37,000
Asset retirement obligation	3,737,000	3,455,000
Total liabilities	125,112,000	107,457,000
Partners' Capital	151,462,000	147,253,000
Unitholders' equity:	'	'
Total New Source Energy Partners L.P. unitholders' equity	137,474,000	133,265,000
Non-controlling interest in subsidiary	13,988,000	13,988,000
Total unitholders' equity	151,462,000	147,253,000
Total liabilities and unitholders' equity	276,574,000	254,710,000
Common Units	'	'
Current liabilities:	'	'
Partners' Capital	157,629,000	151,773,000
Unitholders' equity:	'	'
Common units (10,088,245 units issued and outstanding at March 31, 2014)	'	151,773,000
Subordinated Units	'	'
Current liabilities:	'	'
Partners' Capital	-18,873,000	-17,334,000
Unitholders' equity:	'	'
Subordinated units (2,205,000 units issued and outstanding at March 31, 2014)	'	-17,334,000
General Partnership Units	'	'
Current liabilities:	'	'
Partners' Capital	-1,282,000	-1,174,000
Unitholders' equity:	'	'
General partner's units (155,102 units issued and outstanding at March 31, 2014)	'	($1,174,000)

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Unaudited) (Parentheticals)	Mar. 31, 2014
Statement of Financial Position [Abstract]	'
Common units outstanding (in Shares)	10,088,245
Subordinated units outstanding (in Shares)	2,205,000
General partner's capital units outstanding (in Shares)	155,102

Condensed_Statements_of_Operat

Condensed Statements of Operations (Unaudited) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
REVENUES	'	'
Oil sales	$3,947	$1,198
Natural gas sales	5,367	1,807
Natural gas liquids sales	9,537	6,355
Service and rentals	8,576	0
Total revenues	27,427	9,360
OPERATING COSTS AND EXPENSES	'	'
Oil and natural gas production expenses	4,503	2,447
Oil and natural gas production taxes	879	953
Cost of providing service and rentals (excluding depreciation)	4,566	0
General and administrative	5,127	8,854
Depreciation, depletion and amortization	9,279	3,195
Accretion expense	68	29
Total operating costs and expenses	24,422	15,478
Operating income (loss)	3,005	-6,118
OTHER INCOME (EXPENSE)	'	'
Interest expense	-969	-2,079
Loss from derivatives, net	-3,132	-5,326
Other loss	-435	0
Loss before income taxes	-1,531	-13,523
Income tax benefit	0	12,126
Net loss	-1,531	-1,397
Common Units	'	'
OTHER INCOME (EXPENSE)	'	'
Net loss	-1,241	-4,648
ALLOCATION OF NET LOSS FOR THREE MONTHS ENDED MARCH 31,	'	'
Basic and diluted income per unit (in usd per unit)	($0.12)	($0.87)
Subordinated Units	'	'
OTHER INCOME (EXPENSE)	'	'
Net loss	-271	-1,919
ALLOCATION OF NET LOSS FOR THREE MONTHS ENDED MARCH 31,	'	'
Basic and diluted income per unit (in usd per unit)	($0.12)	($0.87)
General Partnership Units	'	'
OTHER INCOME (EXPENSE)	'	'
Net loss	($19)	($133)
ALLOCATION OF NET LOSS FOR THREE MONTHS ENDED MARCH 31,	'	'
Basic and diluted income per unit (in usd per unit)	($0.12)	($0.87)

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Unitholders' Equity (Unaudited) (USD $)	Total	Common Units	Subordinated Units	General Partnership Units	New Source Energy Partners LP	Noncontrolling Interest
In Thousands, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2013	$147,253	$151,773	($17,334)	($1,174)	$133,265	$13,988
Beginning Balance (in units) at Dec. 31, 2013	'	9,599,578	2,205,000	155,102	'	'
Increase (Decrease) in Partners' Capital [Roll Forward]	'	'	'	'	'	'
Purchase of oil and natural gas properties in exchange for units (in units)	'	488,667	'	'	'	'
Purchase of oil and natural gas properties in exchange for units	11,620	11,620	'	'	11,620	'
Offering cost related to 2013 private placement paid in 2014	-100	-100	'	'	-100	'
Unit compensation funded by unitholders	258	258	'	'	258	'
Cash distributions to unitholders	-6,038	-4,681	-1,268	-89	-6,038	'
Net loss	-1,531	-1,241	-271	-19	-1,531	'
Ending Balance at Mar. 31, 2014	$151,462	$157,629	($18,873)	($1,282)	$137,474	$13,988
Ending Balance (in units) at Mar. 31, 2014	'	10,088,245	2,205,000	155,102	'	'

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Cash Flow (Unaudited) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES	'	'
Net loss	($1,531)	($1,397)
Adjustments to reconcile net loss to net cash provided by operating activities:	'	'
Depreciation, depletion and amortization	9,279	3,195
Write off of loan fees due to debt refinancing	0	1,436
Equity-based compensation	258	7,738
Deferred income tax expense (benefit)	0	-12,023
Business Combination, Contingent Consideration Arrangements, Change in Amount of Contingent Consideration, Liability	433	0
Other non-cash charges	0	37
Amortization of loan fees	0	129
Accretion expense	68	29
Unrealized gain (loss) on derivatives, net	703	5,068
Payments for derivative option premiums	0	-1,334
Changes in operating assets and liabilities:	'	'
Accounts receivable	-5,117	-5,953
Other current assets	-454	0
Accounts payable	2,226	2,324
Accrued liabilities	544	-154
Income taxes payable	0	-103
Net cash provided by (used) in operating activities	6,409	-1,008
CASH FLOWS FROM INVESTING ACTIVITIES	'	'
Additions to other property and equipment	-814	0
Acquisition of oil and natural gas properties	-6,900	0
Additions to oil and natural gas properties	-10,372	-112
Net cash used in investing activities	-18,086	-112
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Payments on long-term debt	-245	-95,000
Payments on factoring payable	-1,907	0
Payments for deferred loan costs	-267	-1,634
Payments of offering costs	-100	0
Proceeds from sales of common units, net of offering costs	0	77,880
Proceeds from borrowings on long-term debt	225	0
Proceeds from credit facility	2,147	0
Distribution to unitholders	-6,038	0
Distribution to parent	0	-18,295
Net cash provided by financing activities	5,315	4,951
Net change in cash and cash equivalents	-6,362	3,831
Cash and cash equivalents, beginning of period	7,291	0
Cash and cash equivalents, end of period	929	3,831
SUPPLEMENTAL CASH FLOW INFORMATION	'	'
Cash paid for interest expense	999	668
NON-CASH INVESTING AND FINANCING ACTIVITIES	'	'
Capitalized asset retirement obligation	214	1,335
Decrease in accrued capital expenditures	0	-234
Accounts receivable distributed to parent	0	-7,014
Accounts payable assumed by parent	0	-1,742
Subordinated note given to parent in exchange for oil and gas properties	0	25,000
Purchase of oil and natural gas properties in exchange for units	-11,620	-27,983
Acquisition of property and equipment by financing	2,329	0
Revolving Credit Facility	'	'
CASH FLOWS FROM FINANCING ACTIVITIES	'	'
Proceeds from credit facility	$11,500	$42,000

Basis_of_Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Presentation	'
	1.  Basis of Presentation
	Nature of Business.  We are a Delaware limited partnership formed in October 2012 by New Source Energy to own and acquire oil and natural gas properties in the United States. In November 2013, we acquired an oilfield services business, and now we report our results of operations and describe our business in two segments: (i) exploration and production and (ii) oilfield services. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions.
	Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation, a conventional resource reservoir located in east central Oklahoma. We also operate an oilfield services business that provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, throughout the Mid-Continent region, South Texas and West Texas.
	Principles of Consolidation. The unaudited condensed consolidated financial statements include the accounts of the Partnership and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
	Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2013 have been derived from the audited financial statements contained in the Partnership’s 2013 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2013 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2013 Form 10-K.
	Significant Accounting Policies. For a description of the Partnership’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2013 Form 10-K.
	Use of Estimates. Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves. Other significant estimates include, but are not limited to, the valuation of commodity derivatives, the allocation of general and administrative expenses, and asset retirement obligations.
	Oil and Natural Gas Properties. The Partnership utilizes the full cost method of accounting for oil and natural gas properties whereby productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. All capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves. Under the full cost method, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the ceiling limitation). In arriving at estimated after-tax future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. Reserve estimates used in determining estimated after-tax future net revenues have been prepared by an internal petroleum engineer. Future net revenues were computed based on reserves using prices calculated as the unweighted arithmetical average oil and natural gas prices on the first day of each month within the latest twelve-month period. Subsequent to February 13, 2013, the ceiling limitation computation is determined without regard to income taxes due to the Partnership being a non-income tax paying entity. There were no full cost ceiling write-downs recorded in the three months ended March 31, 2014 or 2013.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2014
Business Combinations [Abstract]	'
Acquisitions	'
	Acquisitions
	CEU Acquired Properties
	On January 31, 2014, we completed the acquisition of the CEU Acquired Properties, which included working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma, from CEU Paradigm, LLC ("CEU"). The acquisition was accounted for under FASB ASC 805, "Business Combinations."
	As consideration for the working interests, we paid $6.9 million in cash and issued 488,667 common units valued at $23.78 per common unit ($11.6 million in common units) for total consideration of $18.5 million less a purchase price adjustment of $0.2 million for fair value of assets acquired of $18.3 million. We also agreed to provide additional consideration to CEU in November 2014 if the production attributable to the working interests for the nine-month period ending September 30, 2014 exceeds a certain production average, which was valued at $0 on the acquisition date. We may satisfy any such additional consideration in cash, common units, or a combination thereof at our discretion.
	This transaction was unanimously approved by the board of directors of the Partnership's general partner. The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
		January 31, 2014
	Proved oil and natural gas properties	$	18,521
	Fair value of assets acquired	18,521
	Asset retirement obligations	(182		)
	Fair value of net assets acquired	$	18,339
	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 values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. See Note 6 "Fair Value Measurements" for additional information.
	Pro Forma Operating Results
	The following table reflects the unaudited pro forma results of operations as though (i) the acquisition of the CEU Acquired Properties had occurred on January 1, 2013 and (ii) the Material Acquisitions (as defined and described in Note 2 to the consolidated financial statements in the 2013 Form 10-K) occurring in 2013 subsequent to the Partnership's initial public offering had occurred on January 1, 2012. The pro forma amounts are not necessarily indicative of the results that may be reported in the future.
	The financial information was derived from the unaudited interim financial statements from January 1, 2014 to January 31, 2014, the closing date of the CEU Acquisition. The financial information for each of the Material Acquisitions was derived from the Material Acquisitions' unaudited interim financial statements from January 1, 2013 to each Material Acquisition closing date.
		Pro Forma
		2014			2013
	Revenues
	As reported	$	27,427		$	9,360
	Pro forma	$	28,392		$	15,858
	Net loss
	As reported	$	(1,531	)	$	(1,397	)
	Pro forma	$	(1,178	)	$	(861	)
	Basic net loss per unit:
	As reported	$	(0.12	)	$	(0.69	)
	Pro forma	$	(0.09	)	$	(0.09	)
	Diluted net loss per unit:
	As reported	$	(0.12	)	$	(0.69	)
	Pro forma	$	(0.09	)	$	(0.09	)
	The amounts of revenues and revenues in excess of direct operating expenses included in our statements of operations for the CEU Acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. The operating income attributable to the CEU Acquisition does not reflect certain expenses, such as general and administrative and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.
		Three Months Ended March 31, 2014
	Revenues	$	1,883
	Excess of revenues over direct operating expenses	$	1,119

Credit_Agreement_and_Other_Bor

Credit Agreement and Other Borrowings	3 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
Credit Facility and Other Borrowings	'
	Credit Facility and Other Borrowings
	Credit Facility
	The Partnership's credit facility is a four-year senior secured revolving credit facility and is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. As of March 31, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The credit facility matures in February 2017.
	Additionally, the credit facility contains various covenants and restrictive provisions that, among other things, limit the ability of the Partnership to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. Notwithstanding the foregoing, the credit facility permits the Partnership to make distributions to its common unit holders in an amount not to exceed “Available Cash” (as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the "Partnership Agreement") if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed 90%. At March 31, 2014, under the restrictive terms of our covenants, partners’ capital of $2.25 million was available for distribution.
	The obligations under the credit facility are secured by all of the Partnership's oil and gas properties, which serve as collateral for borrowings under the credit facility. The Partnership was in compliance with all covenants under the credit agreement.
	Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) the Administrative Agent’s prime rate or (c) LIBOR plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Accrued interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans, at shorter intervals and the variable rate was approximately 3.33% per annum at March 31, 2014. The credit facility does not require principal repayments, unless the outstanding balance exceeds the borrowing base. At March 31, 2014, the borrowing base under the credit facility was $102.5 million, and the Partnership had $90 million outstanding under the credit agreement with $12.5 million of available borrowing capacity.
	Factoring Payable
	The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of its oilfield services segment. The Partnership received 90% funding immediately, and 10% was held in a reserve account with the factoring company for each invoice that was factored. Customers remitted payments directly to the factoring company. Proceeds from the arrangement were reflected as borrowings in our financial statements.
	The outstanding balance was $1.9 million as of December 31, 2013. All outstanding balances were paid and the agreement was terminated in February 2014, when MCE established its line of credit with Bank of Oklahoma, described below.
	Line of Credit
	On February 11, 2014, MCE entered into a loan agreement with Bank of Oklahoma. The note evidences a revolving line of credit of up to $4.0 million, based on a borrowing base of $3.7 million related to the oilfield services segment's accounts receivable. Interest only payments are due monthly with the note maturing in February 2015. The note replaced MCE's factoring payable agreement described above. Interest on the note accrues at the BOKF National Prime Rate. The note is secured by accounts receivable, inventory, chattel paper and general intangibles of MCE and had an outstanding balance of $2.1 million as of March 31, 2014 and, as a result had $1.6 million of available borrowing capacity.

LongTerm_Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	In addition to the amounts described in Note 3 above, the Partnership has $4.5 million in debt as of March 31, 2014 related to financing notes with various lending institutions for certain property and equipment through MCE. These notes range from 36-60 months in duration with maturity dates from May 2016 through April 2018 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCE and are secured by such assets.
	The following is a schedule by years of minimum principal payments required under the Partnership's long-term debt and credit facility for the periods ending March 31, (in thousands):
	Year	Amount
	2015	$	1,632
	2016	1,732
	2017 (1)	91,039
	2018	132
	2019	7
	Total	$	94,542
	(1) Includes Credit Facility borrowings of $90.0 million maturing in February 2017.

Derivative_Contracts

Derivative Contracts	3 Months Ended
	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Contracts	'
	Derivative Contracts
	Due to the volatility of oil and natural gas prices, the Partnership periodically enters into price-risk management transactions (e.g. swaps, collars or puts) for a portion of its oil, natural gas and natural gas liquids production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and natural gas liquids, it also reduces the Partnership’s potential exposure to adverse price movements. The Partnership’s arrangements, to the extent it enters into any, apply to only a portion of its expected production, provide only partial price protection against declines in oil and natural gas prices and limit the Partnership’s potential gains from future increases in prices. None of these instruments is used for trading or speculative purposes.
	Under Financial Accounting Standards Board Accounting Standards Codification ("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. The Partnership will net derivative assets and liabilities for counterparties where it has a legal right of offset. Changes in the derivatives' fair values are recognized currently in earnings since the Partnership has elected not to designate its current derivative contracts as hedges. See discussion of fair value instruments at Note 6.
	By using derivative instruments to mitigate exposures to changes in commodity prices, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk. Such credit risk is mitigated by the fact that the Partnership's derivatives counterparties are major financial institutions with investment grade credit ratings, some of which are lenders under the Partnership's credit facility.  In addition, the Partnership routinely monitors the creditworthiness of its counterparties.
	The following table sets forth a reconciliation of the changes in fair value of the Partnership's commodity derivatives for the three months ended March 31, 2014 and the year ended December 31, 2013 (in thousands):
		March 31, 2014				December 31, 2013
	Beginning fair value of commodity derivatives	$	(2,414	)		$	(129	)
	Total loss on commodity derivatives	(3,132		)		(5,548		)
	Commodity derivative premiums paid	—				1,334
	Commodity derivative cash settlements paid	2,429				1,929
	Ending fair value of commodity derivatives	$	(3,117	)		$	(2,414	)
	Certain of our commodity derivatives are presented on a net basis on the Condensed Consolidated Balance Sheets. The following table summarizes the gross fair values of our commodity derivative instruments, presenting the impact of offsetting the derivative assets and liabilities recorded in other assets and derivative obligations on our Condensed Consolidated Balance Sheets as of the periods indicated below (in thousands):
		March 31, 2014
		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset in the Condensed Consolidated Balance Sheet				Net Amounts Presented in the Condensed Consolidated Balance Sheet
	Offsetting Derivative Assets:
	Commodity derivatives	$	2,130			$	(1,441	)		$	689
	Offsetting Derivative Liabilities:
	Commodity derivatives	$	(5,247	)		$	1,441			$	(3,806	)
		December 31, 2013
		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset in the Condensed Consolidated Balance Sheet				Net Amounts Presented in the Condensed Consolidated Balance Sheet
	Offsetting Derivative Assets:
	Commodity derivatives	$	2,980			$	(2,190	)		$	790
	Offsetting Derivative Liabilities:
	Commodity derivatives	$	(5,394	)		$	2,190			$	(3,204	)
	The following tables present our derivative instruments outstanding as of March 31, 2014:
	Oil collars:	Volumes			Floor Price				Ceiling Price
		(Bbls)
	2014	66,600			$	80			$	103.5
	2015	42,649			$	80			$	93.25
	Natural gas collars:	Volumes			Floor Price				Ceiling Price
		(MMBtu)
	2014	1,253,003			$	4			$	4.41
	2015	1,364,382			$	4			$	4.32
	Oil put options:	Volumes (Bbls)			Floor Price
	2014	21,148			$	80
	Natural gas put options:	Volumes			Floor Price
		(MMBtu)
	2014	384,354			$	3.5
	2015	798,853			$	3.5
	2016	930,468			$	3.5
	Natural gas liquids put options:	Volumes (Bbls)			Average Floor
					Price
	2014	51,290			$	28.66
	Oil swaps:	Volumes (Bbls)			Fixed Price per
					Bbl
	2014	9,662			$	90.2
	2015	39,411			$	88.9
	2016	36,658			$	86
	Natural gas swaps:	Volumes			Average Price per
		(MMBtu)			MMBtu
	2014	880,591			$	4.09
	2015	800,573			$	4.25
	2016	629,301			$	4.37
	Natural gas liquid swaps:	Volumes			Average Price
		(MMBtu)
	2014	524,133			$	39.76
	2015	84,793			$	82.74

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements	'
	Fair Value Measurements
	Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. As defined in ASC Topic 820-10, fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
	Level 1:     Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Partnership considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
	Level 2:     Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Partnership values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as oil swaps.
	Level 3:     Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The Partnership’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as natural gas liquids swaps, natural gas swaps for those derivatives that are indexed to local and non-observable indices, and oil, natural gas liquids and natural gas collars. Although management utilizes third party broker quotes to assess the reasonableness of our prices and valuation techniques, management does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.
	As required by ASC Topic 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
	Fair Value on a Recurring Basis
	The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 (in thousands):
		Fair Value Measurements at March 31, 2014
	Description	Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
	Oil and natural gas collars	$	—		$	—		$	(459	)	$	(459	)
	Oil and natural gas swaps	—			(274		)	—			(274		)
	Natural gas and natural gas liquid puts	—			—			(347		)	(347		)
	Natural gas liquid swaps	—			—			(2,037		)	(2,037		)
	Balance March 31, 2014	$	—		$	(274	)	$	(2,843	)	$	(3,117	)
	The Partnership estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. The Partnership validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. The Partnership estimates the option value of puts and calls combined into hedges, market prices, contract parameters and discount rates based on published LIBOR rates. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counter parties are major financial institutions with investment grade credit ratings, some of which are lenders under the Partnership’s credit facility. In addition, the Partnership routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change.
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):
		Significant Unobservable Inputs (Level 3)
		Three Months Ended March 31,
		2014			2013
	Beginning balance	$	(2,517	)	$	(112	)
	Losses	(2,432		)	(3,057		)
	Settlements paid	2,106			315
	Ending balance	$	(2,843	)	$	(2,854	)
	Change in unrealized losses included in earnings relating to derivatives still held	$	(702	)	$	(2,742	)
	During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.
	See discussion regarding derivative classifications at Note 5.
	Fair Value on a Non-Recurring Basis
	The Partnership follows the provisions of ASC Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to the Partnership, ASC Topic 820-10, applies to common units issued for compensation purposes, the initial recognition of asset retirement obligations for which fair value is used and the considerations exchanged and certain nonfinancial assets and liabilities as may be acquired in business combinations.
	The Partnership utilizes ASC Topic 718, “Compensation-Stock Compensation,” to value common units issued for compensation purposes. Measurement of unit-based payment transactions with employees is generally based on the grant date fair value of the equity instruments issued.
	Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of November 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. Goodwill was valued using significant inputs that are not observable in the market which are defined as Level 3 inputs pursuant to fair value measurement accounting. The Partnership believes its estimates and assumptions are reasonable, however, there is significant judgment involved.
	Asset retirement cost estimates are derived from historical costs as well as the Partnership’s expectation of future cost to retire assets. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these measurements as Level 3.
	The carrying amount of the credit facility of $90 million as of March 31, 2014 approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings. The credit facility is classified as a Level 2 item within the fair value hierarchy.
	The fair value of the consideration and assets acquired and liabilities assumed related to acquisitions (See Note 2) are classified as a Level 3 item within the fair value hierarchy.

Asset_Retirement_Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligation	'
	Asset Retirement Obligations
	ASC Topic 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Partnership's credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
	The following table reflects the changes in ARO during the three months ended March 31, 2014 and year ended December 31, 2013 (in thousands):
		March 31, 2014		December 31, 2013
	Asset retirement obligation - beginning of period	$	3,455	$	1,510
	Liabilities incurred from acquisitions and new wells drilled	214		1,585
	Revision of previous estimates	—		151
	Current period accretion	68		209
	Asset retirement obligation - end of period	$	3,737	$	3,455

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	The Partnership is controlled by the Partnership's general partner, which is owned 69.4% by Kristian Kos, the President and Chief Executive Officer of our general partner, and 25.0% by the Chairman and Senior Geologist of our general partner, David J. Chernicky. Mr. Kos beneficially owns approximately 7.9% of the Partnership's outstanding common units, including common units awarded under the Partnership's long-term incentive plan, and units owned through Deylau, LLC, an entity he controls. Mr. Chernicky beneficially owns approximately 26.3% of the Partnership's outstanding common units, including common units awarded under the Partnership's long-term incentive plan, and units owned through New Source Energy and Scintilla, entities that he controls. In addition, Mr. Chernicky beneficially owns 100% of the 2,205,000 subordinated units through his control of New Source Energy. Mr. Chernicky owns all of the membership interests in New Dominion, which operates all of the Partnership's oil and gas properties.
	New Dominion
	New Dominion is an exploration and production operator based in Tulsa, Oklahoma and is wholly-owned by Mr. Chernicky. Pursuant to various development agreements with the Partnership, New Dominion is currently contracted to operate the Partnership’s existing wells. New Dominion has historically performed this service for New Source Energy.
	New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated is approximately $0.4 million as of March 31, 2014, all of which is classified as a long-term liability, and was $0.4 million as of December 31, 2013, all of which is classified as a long-term liability. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.
	The expenses incurred by the Partnership billed by New Dominion consist of the following:
	•	producing overhead charges included in the Partnership properties’ oil and natural gas expenses;
	•	drilling and completion overhead charges included in the Partnership properties’ full cost pool of oil and natural gas properties;
	•	saltwater disposal costs or access fee charges included in the Partnership's capitalized oil and gas properties full cost pool and salt water disposal fees included in oil and natural gas production expenses;
	The expense amount incurred for these charges are as follows for the three months ended March 31, (in thousands):
			2014		2013
	Producing overhead charges		$	375	$	170
	Drilling and completion overhead charges		9		17
	Saltwater disposal fees		415		79
	Total expenses incurred		$	799	$	266
	New Source Energy
	On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among New Source Energy, the Partnership and our general partner. Pursuant to the Omnibus Agreement, New Source Energy provided management and administrative services for the Partnership and our general partner for the year ended December 31, 2013. From the closing of the offering through December 31, 2013, the Partnership incurred a quarterly fee of $0.7 million for the provision of such services, totaling $2.4 million for the year ended December 31, 2013, which included a prorated fee of $0.4 million for the period from February 13, 2013 through March 31, 2013, in its general and administrative expenses. After December 31, 2013, in lieu of the quarterly fee, our general partner reimburses New Source Energy, on a quarterly basis, for the actual direct and indirect expenses it incurs in its performance under the Omnibus Agreement, and the Partnership reimburses our general partner for such payments it makes to New Source Energy. At March 31, 2014, amounts owed under the Omnibus Agreement related only to charges incurred during 2013. This amount was $1.0 million and all of which was paid in April 2014. There were no amounts incurred under the Omnibus Agreement for 2014 due to the expiration of the agreement as of December 31, 2013. Prior to February 13, 2013, the Partnership’s consolidated financial statements reflected an allocated portion of the general and administrative expenses of the owner of the IPO Properties.
	New Source Energy Partners, G.P.
	Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three months ended March 31, 2014 we incurred approximately $338,000 in expenses from our general partner.
	Oilfield Services Segment
	Mr. Kos was a 36% owner of MCE prior to the MCE Acquisition and continues to hold Class B units of MCE.
	Dikran Tourian, the President of our oilfield services segment, was a 36% owner of MCE prior to the MCE Acquisition and continues to hold Class B units of MCE, and was appointed to serve as a member of the board of directors of our general partner in February 2014.
	MCE Class B units are entitled to certain distribution rights if certain thresholds are met. During the three months ended March 31, 2014, these thresholds were not met and no distributions were made to Class B unitholders. For additional information regarding MCE Class B units see Note 12 "Unitholders' Equity" in the 2013 Form 10-K.
	Transactions with Directors and Officers
	The Partnership engaged Finley & Cook, PLLC (“Finley & Cook”) to provide various accounting services on our behalf during the period ended March 31, 2014. Richard Finley, the Chief Financial Officer of our general partner, is an equity member of Finley & Cook, holding a 31.5% ownership interest. The Partnership paid Finley & Cook approximately $146,000 in fees for accounting services for the three months ended March 31, 2014.
	New Source Energy, through the Omnibus Agreement, engaged Finley & Cook, PLLC (“Finley & Cook”) to provide various accounting services on our behalf during the year ended December 31, 2013. Fees for such services provided during the three months ended March 31, 2013 were approximately $108,000.

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies	'
	Commitments and Contingencies
	Commitments
	The Partnership is a party to various agreements under which it has rights and obligations to participate in the acquisition and development of undeveloped properties held and to be acquired by Scintilla and New Dominion. These properties will be held by New Dominion for the benefit of the Partnership pending development of the properties. The Partnership is required by its underlying agreements with New Dominion to pay certain acreage fees to reimburse New Dominion for the cost of the acreage attributable to the Partnership’s working interest when invoiced by New Dominion. The Partnership recognizes an asset and corresponding liability as the acreage costs are incurred by New Dominion (see Note 8).  The agreements require us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. There are significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements. The agreements also require us to pay New Dominion our proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.
	On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into a development agreement (the “Development Agreement”) with New Source Energy and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, the Partnership has agreed to maintain an average annual maintenance drilling budget of at least $8.2 million to drill certain of the Partnership’s proved undeveloped locations and maintain the Partnership’s producing wells.
	Pursuant to the Development Agreement, our general partner will, at least annually, at its discretion, determine the Partnership’s maintenance drilling budget. The general partner will also have the right to propose which wells are drilled based on the Partnership’s maintenance drilling budget. Under the Development Agreement, New Dominion will use its commercially reasonable best efforts to (i) conduct its operations such that the Partnership’s proportionate share of capital expenses that it would consider maintenance capital is equal to the annual maintenance drilling budget set by our general partner and (ii) cause the wells drilled pursuant to such participation agreements to be consistent with the maintenance drilling schedule proposed by our general partner. Our general partner will also have the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.
	Legal Matters
	New Dominion is a defendant in a legal proceeding arising in the normal course of its business, which may impact the Partnership as described below.
	In the case of Mattingly v. Equal Energy, LLC, New Dominion is a named defendant. In this case, the plaintiffs assert claims on behalf of a class of royalty owners in wells operated by New Dominion and others from which natural gas is sold by New Dominion to Scissortail Energy, LLC. The plaintiffs assert that royalties to the class should be paid based upon the price received by Scissortail for the gas and its components at the tailgate of the plant, rather than the price paid by Scissortail at the wellhead where the gas is purchased. The plaintiffs assert a variety of breach of contract and tort claims. The case was originally filed in the District Court of Creek County, Oklahoma and was removed by the defendants to the federal court but was remanded to state court on August 1, 2011.
	Any liability on the part of New Dominion, as operator, would be allocated to the working interest owners to pay their proportionate share such liability. While the outcome and impact on the Partnership of this proceeding cannot be predicted with certainty, management believes a range of loss from $10,000 to $250,000 may be reasonably possible.
	The Partnership may be involved in other various routine legal proceedings incidental to its business from time to time. However, there were no other material pending legal proceedings to which the Partnership is a party or to which any of its assets are subject.

Earnings_and_Distributions_Per

Earnings and Distributions Per Common and Subordinated Unit	3 Months Ended
	Mar. 31, 2014
Earnings Per Share [Abstract]	'
Earnings and Distributions Per Common and Subordinated Unit	'
	Earnings and Distributions Per Common and Subordinated Unit
	The computations of basic earnings per common unit and subordinated unit are based on the weighted average number of common units and subordinated units, respectively, outstanding during the applicable period. The Partnership’s subordinated units meet the definition of a participating security; therefore, the Partnership is required to use the two-class method in the computation of earnings per unit. Basic earnings per common unit and subordinated unit are determined by dividing net income allocated to the common units and subordinated units, respectively, after deducting the amount allocated to the Partnership’s general partner (including distributions to the general partner on its incentive distribution rights), by the weighted average number of outstanding common units and subordinated units, respectively, during the period. The Partnership has no potential common units outstanding. Therefore, the amounts of basic and diluted earnings per unit are the same.
	Pursuant to our Partnership Agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. The Partnership’s earnings per unit calculations, which allocated 1.25% of earnings to our general partner with respect to the three months ended March 31, 2014, reflect that, while such distribution to our general partner with respect to its 1.25% general partner interest was made, no incentive distributions were permitted to be, or were, made to our general partner because quarterly distributions declared by the board of directors for the first quarter of 2014 did not exceed the specified targets.
	Basic and diluted earnings per unit for the period ended March 31, 2014 and 2013 were computed using the following components:
	For the three months ended March 31, 2014	Common Units			Subordinated Units			General Partner
	Numerator:
	Net loss (in thousands)	$	(1,241	)	$	(271	)	$	(19	)
	Denominator:
	Weighted average units outstanding	9,919,926			2,205,000			155,102
	Basic and diluted income per unit	$	(0.12	)	$	(0.12	)	$	(0.12	)
	For the three months ended March 31, 2013	Common Units			Subordinated Units			General Partner
	Numerator:
	Net loss subsequent to purchase of properties form New Source Energy on February 13, 2013	$	(4,648	)	$	(1,919	)	$	(133	)
	Denominator:
	Weighted average units outstanding	5,395,000			2,205,000			155,102
	Basic and diluted income per unit	$	(0.87	)	$	(0.87	)	$	(0.87	)
	Distributions during the three months ended March 31, 2014 and 2013 were as follows:
		2014 Distributions			2013 Distributions
	Per Unit	$	0.575		$	—
	Amount Paid to Common Unitholders	$	4,681		$	—
	Amount Paid to Subordinated Unitholders	$	1,268		$	—
	Amount Paid to General Unitholders	$	89		$	—
	Total Distributions	$	6,038		$	—

EquityBased_Compensation

Equity-Based Compensation	3 Months Ended
	Mar. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Equity-based Compensation	'
	Equity-based Compensation
	On February 13, 2013, the Partnership granted 367,500 restricted common units to consultants, officers and other employees. Disposition of these units is restricted until the later of the termination of the subordination period or December 31, 2015. The awards were valued at the initial public offering price of $20.00 per common unit and charged to equity-based compensation in general and administrative expenses at the date of the award. The restricted units do not contain a future service requirement from the recipients, so the amounts were fully vested as of February 13, 2013 and the Partnership recorded compensation expense of $7.7 million related to these awards as general and administrative expense in the accompanying Condensed Consolidated Statements of Operations for the three months ended March 31, 2013.
	On November 12, 2013, as part of the MCE Acquisition, the Partnership granted 99,768 restricted common units to employees of MCE valued at $2.3 million that were included as part of the purchase price of the MCE Acquisition, which were all outstanding as of December 31, 2013. The units will vest over one to three years, and are subject to vesting restrictions based on employment status. If such common units are forfeited for any reason prior to vesting, then within forty-five days of the end of each calendar year beginning on December 31, 2014, any such forfeited units will be issued by the Partnership to the former owners of MCE. Equity-based compensation expense will be recognized straight-line over the vesting period equal to the grant date fair value of these units. For the three months ended March 31, 2014, the Partnership recognized $0.26 million in equity-based compensation expense, which is presented as "Unit compensation funded by unitholders" on the accompanying Condensed Consolidated Statements of Unitholders' Equity and as general and administrative expense in the accompanying Condensed Consolidated Statements of Operations for the three months ended March 31, 2014.
	Unamortized equity-based compensation expense related to these awards was $1.9 million as of March 31, 2014 and will be recognized on a straight line basis through January 1, 2017.
	On August 18, 2011, New Source Energy granted 2,900,000 shares of restricted common stock, with 1,000,000 shares vesting upon the first anniversary of the date of grant, 700,000 shares vesting on the second anniversary of the date of grant, and the remaining 1,200,000 shares vesting on the completion of an initial public offering of New Source Energy's common stock pursuant to a filed prospectus provided that the recipients remained employed by New Source Energy on the applicable vesting dates, subject to limited exceptions ("2011 Grant"). An allocated amount of New Source Energy stock-based compensation related to these awards in the amount of $0.4 million for the period from January 1, to February 13, 2013 was recognized in the Partnership's financial statements as general and administrative expense in the accompanying Consolidated Statements of Operations for the three months ended March 31, 2013.
	Based on all of the foregoing grants, the Partnership recorded the following equity-based compensation expense for the three months ended March 31, (in thousands):
		2014		2013
	Total equity-based compensation	$	258	$	7,738
	Equity-based compensation allocated from New Source Energy	$	—	$	400

Contingent_Consideration

Contingent Consideration	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Contingent Consideration	'
	Contingent Consideration
	A reconciliation of the beginning and ending balances of acquisition-related accrued earnouts using significant unobservable inputs (Level 3) for the three months ended March 31, 2014 is as follows (in thousands):
		2014
	Accrued earnout liability as of December 31, 2013	$	6,320
	Acquisition date fair value of contingent consideration - CEU Acquisition	—
	Change in fair value of contingent consideration	433
	Payment of contingent consideration	—
	Accrued earnout liability as of March 31, 2014	$	6,753
	The former owners of MCE are entitled to receive additional Partnership common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $120 million cap. The contingent consideration was valued at $6.3 million at the acquisition date and was considered as a part of the purchase price for the MCE Acquisition. The fair value of this obligation will be valued quarterly and adjusted through earnings accordingly. The estimated fair value of this obligation to the former MCE owners as of March 31, 2014, was $6.8 million and is presented in contingent consideration payable to related parties on the accompanying Consolidated Balance Sheets. The fair value of the contingent consideration was determined through the use of a Monte Carlo simulation, which takes a model with user-defined variables and runs it repeatedly, using a different value for each variable during each run, or trial. The simulation randomly generates the value used for each variable in each trial; however, the user defines permitted and most likely values of the variables through the use of probability distributions.
	The Partnership agreed to provide additional consideration to Scintilla in November 2014 if the production attributable to the Southern Dome Acquired Properties for the nine-month period ending September 30, 2014 exceeded the average daily production of 383.5 Boe/d during the period January 1, 2014 to September 30, 2014. We may satisfy any such additional consideration in cash, Partnership common units, or a combination thereof at our discretion. The contingent consideration was valued at $1.6 million at the acquisition date and was considered as part of the purchase price of the Southern Dome Acquired Properties. The fair value of this liability will be adjusted through earnings accordingly. Based on current estimated production levels for the nine-month period ending September 30, 2014, the Partnership estimated the fair value as of December 31, 2013 and March 31, 2014 is $0. As detailed in the Contribution Agreement, the additional consideration was calculated as the acquisition value of the production increase (applying the same valuation methodology as was used to determine the initial consideration with respect to the Current Production Average) less (i) the capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells that were not producing in paying quantities as of the effective date of the acquisition. In addition, the fair value of the contingent consideration was based on the weighted probability of achievement of certain performance milestones. The Partnership may satisfy any such additional consideration in cash, common units, or a combination thereof at its discretion.
	The Partnership agreed to provide additional consideration to CEU in November 2014 if the production attributable to the CEU Acquired Properties for the nine-month period ending September 30, 2014 exceeded the average daily production of 566 Boe/d during the period January 1, 2014 to September 30, 2014. We may satisfy any such additional consideration in cash, Partnership common units, or a combination thereof at our discretion. The contingent consideration was valued at $0 million at the acquisition date and was considered as part of the purchase price of the CEU Acquired Properties. The fair value of the contingent consideration of $0 million, which represents the probability weighted contingent payment as a percentage of high, mid, and low production projections, will be adjusted through earnings accordingly. Based on current estimated production levels for the nine-month period ending September 30, 2014, the Partnership estimated the fair value as of March 31, 2014 is $0. As detailed in the Contribution Agreement, the additional consideration was calculated as the acquisition value of the production increase (applying the same valuation methodology as was used to determine the initial consideration with respect to the Current Production Average) less (i) the capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells that were not producing in paying quantities as of the effective date of the acquisition. In addition, the fair value of the contingent consideration was based on the weighted probability of achievement of certain performance milestones. The Partnership may satisfy any such additional consideration in cash, common units, or a combination thereof at its discretion.

Business_Segment_Information

Business Segment Information	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
Business Segment Information	'
	Business Segment Information
	The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services.
	Management evaluates the performance of the Partnership’s business segments based on income (loss) from operations. Summarized financial information concerning the Partnership’s segments is shown in the following table (in thousands):
		Exploration and Production			Oilfield Services			Total
	Three Months Ended March 31, 2014
	Revenues	$	18,851		$	8,576		$	27,427
	Operating costs	(5,382		)	(4,566		)	(9,948		)
	Segment margin	$	13,469		$	4,010		$	17,479
	Capital expenditures	$	17,275		$	811		$	18,086
	Depreciation, depletion and amortization	$	5,819		$	3,460		$	9,279
	Three Months Ended March 31, 2013
	Revenues	$	9,360		$	—		$	9,360
	Operating costs	(3,400		)	—			(3,400		)
	Segment margin	$	5,960		$	—		$	5,960
	Capital expenditures	$	112		$	—		$	112
	Depreciation, depletion and amortization	$	3,195		$	—		$	3,195
	The following table reconciles the segment profits reported above to operating loss as reported on the Condensed Consolidated Statements of Operations for the three months ended March 31, (in thousands):
		2014			2013
	Segment margin	$	17,479		$	5,960
	Depreciation, depletion and amortization	(9,279		)	(3,195		)
	General and administrative	(5,127		)	(8,854		)
	Accretion	(68		)	(29		)
	Operating income/(loss)	$	3,005		$	(6,118	)

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2014
Subsequent Events [Abstract]	'
Subsequent Events	'
	Subsequent Events
	Shelf Registration Statement
	On April 8, 2014, we filed a registration statement with the SEC which registered offerings of up to $500.0 million of any combination of common units and preferred units. Net proceeds, terms and pricing of each offering of securities issued under the shelf registration statement will be determined at the time of such offerings. Our ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of common units or preferred units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.
	Equity Offering
	On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. The offering was made pursuant to a prospectus supplement to the shelf registration statement described above. We received net proceeds of approximately $75.8 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.8 million. We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds being deposited in a Partnership bank account to be used for working capital, organic growth, acquisitions, potential further repayments of debt and other general corporate purposes.

Basis_of_Presentation_Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Presentation	'
	Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2013 have been derived from the audited financial statements contained in the Partnership’s 2013 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2013 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2013 Form 10-K.
Use of Estimates	'
	Use of Estimates. Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves. Other significant estimates include, but are not limited to, the valuation of commodity derivatives, the allocation of general and administrative expenses, and asset retirement obligations.
Oil and Gas Properties	'
	Oil and Natural Gas Properties. The Partnership utilizes the full cost method of accounting for oil and natural gas properties whereby productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. All capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves. Under the full cost method, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the ceiling limitation). In arriving at estimated after-tax future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. Reserve estimates used in determining estimated after-tax future net revenues have been prepared by an internal petroleum engineer. Future net revenues were computed based on reserves using prices calculated as the unweighted arithmetical average oil and natural gas prices on the first day of each month within the latest twelve-month period. Subsequent to February 13, 2013, the ceiling limitation computation is determined without regard to income taxes due to the Partnership being a non-income tax paying entity.

Acquisitions_Tables

Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2014
Business Combinations [Abstract]	'
Schedule of Business Acquisitions, by Acquisition	'
	The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
		January 31, 2014
	Proved oil and natural gas properties	$	18,521
	Fair value of assets acquired	18,521
	Asset retirement obligations	(182		)
	Fair value of net assets acquired	$	18,339
Business Acquisition, Pro Forma Information	'
	The financial information for each of the Material Acquisitions was derived from the Material Acquisitions' unaudited interim financial statements from January 1, 2013 to each Material Acquisition closing date.
		Pro Forma
		2014			2013
	Revenues
	As reported	$	27,427		$	9,360
	Pro forma	$	28,392		$	15,858
	Net loss
	As reported	$	(1,531	)	$	(1,397	)
	Pro forma	$	(1,178	)	$	(861	)
	Basic net loss per unit:
	As reported	$	(0.12	)	$	(0.69	)
	Pro forma	$	(0.09	)	$	(0.09	)
	Diluted net loss per unit:
	As reported	$	(0.12	)	$	(0.69	)
	Pro forma	$	(0.09	)	$	(0.09	)
	The amounts of revenues and revenues in excess of direct operating expenses included in our statements of operations for the CEU Acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. The operating income attributable to the CEU Acquisition does not reflect certain expenses, such as general and administrative and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.
		Three Months Ended March 31, 2014
	Revenues	$	1,883
	Excess of revenues over direct operating expenses	$	1,119

LongTerm_Debt_Tables

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
Schedule of Maturities of Long-term Debt	'
	The following is a schedule by years of minimum principal payments required under the Partnership's long-term debt and credit facility for the periods ending March 31, (in thousands):
	Year	Amount
	2015	$	1,632
	2016	1,732
	2017 (1)	91,039
	2018	132
	2019	7
	Total	$	94,542
	(1) Includes Credit Facility borrowings of $90.0 million maturing in February 2017.

Derivative_Contracts_Tables

Derivative Contracts (Tables)	3 Months Ended
	Mar. 31, 2014
Derivative [Line Items]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	The following table sets forth a reconciliation of the changes in fair value of the Partnership's commodity derivatives for the three months ended March 31, 2014 and the year ended December 31, 2013 (in thousands):
		March 31, 2014				December 31, 2013
	Beginning fair value of commodity derivatives	$	(2,414	)		$	(129	)
	Total loss on commodity derivatives	(3,132		)		(5,548		)
	Commodity derivative premiums paid	—				1,334
	Commodity derivative cash settlements paid	2,429				1,929
	Ending fair value of commodity derivatives	$	(3,117	)		$	(2,414	)
	The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 (in thousands):
		Fair Value Measurements at March 31, 2014
	Description	Active Markets for Identical Assets (Level 1)				Observable Inputs (Level 2)				Unobservable Inputs (Level 3)			Total Carrying Value
	Oil and natural gas collars	$	—			$	—			$	(459	)	$	(459	)
	Oil and natural gas swaps	—				(274		)		—			(274		)
	Natural gas and natural gas liquid puts	—				—				(347		)	(347		)
	Natural gas liquid swaps	—				—				(2,037		)	(2,037		)
	Balance March 31, 2014	$	—			$	(274	)		$	(2,843	)	$	(3,117	)
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):
		Significant Unobservable Inputs (Level 3)
		Three Months Ended March 31,
		2014				2013
	Beginning balance	$	(2,517	)		$	(112	)
	Losses	(2,432		)		(3,057		)
	Settlements paid	2,106				315
	Ending balance	$	(2,843	)		$	(2,854	)
	Change in unrealized losses included in earnings relating to derivatives still held	$	(702	)		$	(2,742	)
Schedule of Derivative Instruments	'
	The following table summarizes the gross fair values of our commodity derivative instruments, presenting the impact of offsetting the derivative assets and liabilities recorded in other assets and derivative obligations on our Condensed Consolidated Balance Sheets as of the periods indicated below (in thousands):
		March 31, 2014
		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset in the Condensed Consolidated Balance Sheet				Net Amounts Presented in the Condensed Consolidated Balance Sheet
	Offsetting Derivative Assets:
	Commodity derivatives	$	2,130			$	(1,441	)		$	689
	Offsetting Derivative Liabilities:
	Commodity derivatives	$	(5,247	)		$	1,441			$	(3,806	)
		December 31, 2013
		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset in the Condensed Consolidated Balance Sheet				Net Amounts Presented in the Condensed Consolidated Balance Sheet
	Offsetting Derivative Assets:
	Commodity derivatives	$	2,980			$	(2,190	)		$	790
	Offsetting Derivative Liabilities:
	Commodity derivatives	$	(5,394	)		$	2,190			$	(3,204	)
Oil Collar	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Oil collars:	Volumes			Floor Price				Ceiling Price
		(Bbls)
	2014	66,600			$	80			$	103.5
	2015	42,649			$	80			$	93.25
Natural Gas Collars	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Natural gas collars:	Volumes			Floor Price				Ceiling Price
		(MMBtu)
	2014	1,253,003			$	4			$	4.41
	2015	1,364,382			$	4			$	4.32
Oil Options	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Oil put options:	Volumes (Bbls)			Floor Price
	2014	21,148			$	80
Natural Gas Options	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Natural gas put options:	Volumes			Floor Price
		(MMBtu)
	2014	384,354			$	3.5
	2015	798,853			$	3.5
	2016	930,468			$	3.5
Natural Gas Liquid Options	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Natural gas liquids put options:	Volumes (Bbls)			Average Floor
					Price
	2014	51,290			$	28.66
Oil Swaps	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Oil swaps:	Volumes (Bbls)			Fixed Price per
					Bbl
	2014	9,662			$	90.2
	2015	39,411			$	88.9
	2016	36,658			$	86
Natural Gas Swaps	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Natural gas swaps:	Volumes			Average Price per
		(MMBtu)			MMBtu
	2014	880,591			$	4.09
	2015	800,573			$	4.25
	2016	629,301			$	4.37
Natural Gas Liquid Swaps	'
Derivative [Line Items]	'
Schedule of Derivative Instruments	'
	Natural gas liquid swaps:	Volumes			Average Price
		(MMBtu)
	2014	524,133			$	39.76
	2015	84,793			$	82.74

Fair_Value_Measurements_Fair_V

Fair Value Measurements Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2014
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	The following table sets forth a reconciliation of the changes in fair value of the Partnership's commodity derivatives for the three months ended March 31, 2014 and the year ended December 31, 2013 (in thousands):
		March 31, 2014			December 31, 2013
	Beginning fair value of commodity derivatives	$	(2,414	)	$	(129	)
	Total loss on commodity derivatives	(3,132		)	(5,548		)
	Commodity derivative premiums paid	—			1,334
	Commodity derivative cash settlements paid	2,429			1,929
	Ending fair value of commodity derivatives	$	(3,117	)	$	(2,414	)
	The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 (in thousands):
		Fair Value Measurements at March 31, 2014
	Description	Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
	Oil and natural gas collars	$	—		$	—		$	(459	)	$	(459	)
	Oil and natural gas swaps	—			(274		)	—			(274		)
	Natural gas and natural gas liquid puts	—			—			(347		)	(347		)
	Natural gas liquid swaps	—			—			(2,037		)	(2,037		)
	Balance March 31, 2014	$	—		$	(274	)	$	(2,843	)	$	(3,117	)
	The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):
		Significant Unobservable Inputs (Level 3)
		Three Months Ended March 31,
		2014			2013
	Beginning balance	$	(2,517	)	$	(112	)
	Losses	(2,432		)	(3,057		)
	Settlements paid	2,106			315
	Ending balance	$	(2,843	)	$	(2,854	)
	Change in unrealized losses included in earnings relating to derivatives still held	$	(702	)	$	(2,742	)

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Change in Asset Retirement Obligation	'
	The following table reflects the changes in ARO during the three months ended March 31, 2014 and year ended December 31, 2013 (in thousands):
		March 31, 2014		December 31, 2013
	Asset retirement obligation - beginning of period	$	3,455	$	1,510
	Liabilities incurred from acquisitions and new wells drilled	214		1,585
	Revision of previous estimates	—		151
	Current period accretion	68		209
	Asset retirement obligation - end of period	$	3,737	$	3,455

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2014
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions	'
	The expense amount incurred for these charges are as follows for the three months ended March 31, (in thousands):
		2014		2013
	Producing overhead charges	$	375	$	170
	Drilling and completion overhead charges	9		17
	Saltwater disposal fees	415		79
	Total expenses incurred	$	799	$	266

Earnings_and_Distributions_Per1

Earnings and Distributions Per Common and Subordinated Unit - (Tables)	3 Months Ended
	Mar. 31, 2014
Earnings Per Share [Abstract]	'
Schedule of Earnings Per Share, Basic and Diluted	'
	Basic and diluted earnings per unit for the period ended March 31, 2014 and 2013 were computed using the following components:
	For the three months ended March 31, 2014	Common Units			Subordinated Units			General Partner
	Numerator:
	Net loss (in thousands)	$	(1,241	)	$	(271	)	$	(19	)
	Denominator:
	Weighted average units outstanding	9,919,926			2,205,000			155,102
	Basic and diluted income per unit	$	(0.12	)	$	(0.12	)	$	(0.12	)
	For the three months ended March 31, 2013	Common Units			Subordinated Units			General Partner
	Numerator:
	Net loss subsequent to purchase of properties form New Source Energy on February 13, 2013	$	(4,648	)	$	(1,919	)	$	(133	)
	Denominator:
	Weighted average units outstanding	5,395,000			2,205,000			155,102
	Basic and diluted income per unit	$	(0.87	)	$	(0.87	)	$	(0.87	)
Schedule of Distributions Paid to Unitholders	'
	Distributions during the three months ended March 31, 2014 and 2013 were as follows:
		2014 Distributions			2013 Distributions
	Per Unit	$	0.575		$	—
	Amount Paid to Common Unitholders	$	4,681		$	—
	Amount Paid to Subordinated Unitholders	$	1,268		$	—
	Amount Paid to General Unitholders	$	89		$	—
	Total Distributions	$	6,038		$	—

EquityBased_Compensation_Table

Equity-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of Share-based Compensation, Activity	'
	Based on all of the foregoing grants, the Partnership recorded the following equity-based compensation expense for the three months ended March 31, (in thousands):
		2014		2013
	Total equity-based compensation	$	258	$	7,738
	Equity-based compensation allocated from New Source Energy	$	—	$	400

Contingent_Consideration_Table

Contingent Consideration (Tables)	3 Months Ended
	Mar. 31, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Schedule of Business Acquisitions by Acquisition, Contingent Consideration	'
	A reconciliation of the beginning and ending balances of acquisition-related accrued earnouts using significant unobservable inputs (Level 3) for the three months ended March 31, 2014 is as follows (in thousands):
		2014
	Accrued earnout liability as of December 31, 2013	$	6,320
	Acquisition date fair value of contingent consideration - CEU Acquisition	—
	Change in fair value of contingent consideration	433
	Payment of contingent consideration	—
	Accrued earnout liability as of March 31, 2014	$	6,753

Business_Segment_Information_T

Business Segment Information (Tables)	3 Months Ended
	Mar. 31, 2014
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information, by Segment	'
	Summarized financial information concerning the Partnership’s segments is shown in the following table (in thousands):
		Exploration and Production			Oilfield Services			Total
	Three Months Ended March 31, 2014
	Revenues	$	18,851		$	8,576		$	27,427
	Operating costs	(5,382		)	(4,566		)	(9,948		)
	Segment margin	$	13,469		$	4,010		$	17,479
	Capital expenditures	$	17,275		$	811		$	18,086
	Depreciation, depletion and amortization	$	5,819		$	3,460		$	9,279
	Three Months Ended March 31, 2013
	Revenues	$	9,360		$	—		$	9,360
	Operating costs	(3,400		)	—			(3,400		)
	Segment margin	$	5,960		$	—		$	5,960
	Capital expenditures	$	112		$	—		$	112
	Depreciation, depletion and amortization	$	3,195		$	—		$	3,195
	The following table reconciles the segment profits reported above to operating loss as reported on the Condensed Consolidated Statements of Operations for the three months ended March 31, (in thousands):
		2014			2013
	Segment margin	$	17,479		$	5,960
	Depreciation, depletion and amortization	(9,279		)	(3,195		)
	General and administrative	(5,127		)	(8,854		)
	Accretion	(68		)	(29		)
	Operating income/(loss)	$	3,005		$	(6,118	)

Basis_of_Presentation_Details

Basis of Presentation (Details)	Mar. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Discount Of Estimated Future Net Revenues	10.00%

Acquisitions_Details

Acquisitions (Details) (USD $)	3 Months Ended			0 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Jan. 31, 2014	Mar. 31, 2014
				CEU Paradigm	CEU Paradigm
				producing_well
Business Acquisition [Line Items]	'	'	'	'	'
Productive Oil Wells, Number of Working Interest Wells Acquired	'	'	'	23	'
Payments to Acquire Oil and Gas Property	$6,900,000	$0	'	$6,900,000	'
Stock Issued During Period, Shares, Acquisition of Oil and Gas Properties	'	'	'	488,667	'
Business Acquisition, Share Price	'	'	'	$23.78	'
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	'	'	'	11,600,000	'
Business Combination, Consideration Transferred	'	'	'	18,500,000	'
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Asset Retirement Obligations	'	'	'	182,000	'
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	'	'	'	18,339,000	'
Business Combination, Contingent Consideration, Liability	$6,753,000	'	$6,320,000	$0	$0

Acquisitions_Purchase_Price_Al

Acquisitions - Purchase Price Allocation of CEU Acquisition (Details) (CEU Paradigm, USD $)	Jan. 31, 2014
In Thousands, unless otherwise specified
CEU Paradigm	'
Business Acquisition [Line Items]	'
Proved oil and natural gas properties	$18,521
Fair value of assets acquired	18,521
Asset retirement obligations	-182
Fair value of net assets acquired	$18,339

Acquisitions_Pro_Forma_Results

Acquisitions - Pro Forma Results of Operations (Details) (USD $)	1 Months Ended	3 Months Ended		11 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Feb. 11, 2013	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Revenues [Abstract]	'	'	'	'
As reported	'	$27,427	$9,360	'
Pro forma	'	28,392	15,858	'
Net loss	'	'	'	'
As reported	5,303	-1,531	-1,397	-6,700
Pro forma	'	($1,178)	($861)	'
Basic net loss per unit:	'	'	'	'
As reported (in usd per unit)	'	($0.12)	($0.69)	'
Pro forma (in usd per unit)	'	($0.09)	($0.09)	'
Diluted net loss per unit:	'	'	'	'
As reported (in usd per unit)	'	($0.12)	($0.69)	'
Pro forma (in usd per unit)	'	($0.09)	($0.09)	'

Acquisitions_Amounts_of_Revenu

Acquisitions - Amounts of Revenues and Revenues in Excess of Direct Operating Expenses Included in Statement of Operations (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Business Acquisition [Line Items]	'	'
Revenues	$27,427	$9,360
Gross Profit	17,479	5,960
CEU Paradigm	'	'
Business Acquisition [Line Items]	'	'
Revenues	1,883	'
Gross Profit	$1,119	'

Credit_Agreement_and_Other_Bor1

Credit Agreement and Other Borrowings (Details) (USD $)	3 Months Ended		3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Mar. 31, 2014	Feb. 11, 2014
			Federal Funds Rate	Minimum	Minimum	Maximum	Maximum	LIBOR Loans	Revolving Credit Facility	MidCentral Energy Services	MidCentral Energy Services
				Base Rate	London Interbank Offered Rate (LIBOR)	Base Rate	London Interbank Offered Rate (LIBOR)	Maximum		Revolving Credit Facility	Revolving Credit Facility
								London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Debt Instrument, Period	'	'	'	'	'	'	'	'	'4 years	'	'
Line of Credit Facility, Current Borrowing Capacity	'	'	'	'	'	'	'	'	$102,500,000	'	$3,700,000
Required Ratio of EBITDA to Interest Expense	2.5	'	'	'	'	'	'	'	'	'	'
Required Ratio of Total Debt to EBITDA	3.5	'	'	'	'	'	'	'	'	'	'
Required Current Ratio	1	'	'	'	'	'	'	'	'	'	'
Debt Instrument, Debt Covenant, Maximum Borrowing Base Utilization, Percent	90.00%	'	'	'	'	'	'	'	'	'	'
Debt Instrument, Debt Covenants, Amount Available for Dividend Distribution	2,250,000	'	'	'	'	'	'	'	'	'	'
Debt Instrument, Basis Spread on Variable Rate	1.00%	'	0.50%	1.50%	2.50%	2.25%	3.25%	3.33%	'	'	'
Line of Credit Facility, Commitment Fee Percentage	0.50%	'	'	'	'	'	'	'	'	'	'
Line of Credit Facility, Amount Outstanding	90,000,000	'	'	'	'	'	'	'	'	2,100,000	'
Line of Credit Facility, Remaining Borrowing Capacity	12,500,000	'	'	'	'	'	'	'	'	1,600,000	'
Factoring Payable, Funding Received Upfront, Percent	90.00%	'	'	'	'	'	'	'	'	'	'
Factoring Payable, Amount of Factors Reserved, Percent	10.00%	'	'	'	'	'	'	'	'	'	'
Factoring Payable	'	1,900,000	'	'	'	'	'	'	'	'	'
Line of Credit Facility, Maximum Borrowing Capacity	'	'	'	'	'	'	'	'	'	'	$4,000,000

LongTerm_Debt_Details

Long-Term Debt (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014
Debt Instrument [Line Items]	'
Long-term Debt	94,542
Notes Payable to Banks [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt	4,500
Minimum | Notes Payable to Banks [Member]	'
Debt Instrument [Line Items]	'
Debt Instrument, Period	'36 months
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Maximum | Notes Payable to Banks [Member]	'
Debt Instrument [Line Items]	'
Debt Instrument, Period	'60 months
Debt Instrument, Interest Rate, Stated Percentage	10.51%

LongTerm_Debt_Schedule_of_Long

Long-Term Debt - Schedule of Long-term Debt (Details) (USD $)	Mar. 31, 2014
Line of Credit Facility [Line Items]	'
2015	$1,632,000
2016	1,732,000
2017	91,039,000	[1]
2018	132,000
2019	7,000
Total	94,542,000
Line of Credit Facility, Amount Outstanding	$90,000,000
[1]	Includes Credit Facility borrowings of $90.0 million maturing in February 2017.

Derivative_Contracts_Details_R

Derivative Contracts (Details) - Reconciliation of Changes in the Fair Value of Commodity Derivative (USD $)	3 Months Ended			12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Dec. 31, 2013
			Commodity Contract	Commodity Contract
Reconciliation of Changes in the Fair Value of Commodity Derivative [Roll Forward]	'	'	'	'
Beginning balance	'	'	($2,414)	($129)
Total loss on commodity derivatives	-3,132	-5,326	-3,132	-5,548
Commodity derivative premiums paid	'	'	0	1,334
Commodity derivative cash settlements paid	'	'	2,429	1,929
Ending balance	($3,117)	'	($3,117)	($2,414)

Derivative_Contracts_Details_O

Derivative Contracts (Details) - Offsetting Commodity Derivative Assets and Liabilities (Commodity, USD $)	Mar. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Commodity	'	'
Derivative [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	$2,130	$2,980
Derivative Asset, Fair Value, Amount Offset Against Collateral	-1,441	-2,190
Derivative Assets, Fair Value, Net	689	790
Derivative Liability, Fair Value, Gross Liability	-5,247	-5,394
Derivative Liability, Fair Value, Amount Offset Against Collateral	1,441	2,190
Derivative Liabilities, Fair Value, Net	($3,806)	($3,204)

Derivative_Contracts_Details_C

Derivative Contracts (Details) - Commodity Derivative Positions Oil Collars (Oil Collar)	Mar. 31, 2014
	bbl
2014	'
Derivative [Line Items]	'
Volumes (Bbls)	66,600
Floor Price (in usd per Bbl)	80
Ceiling Price (in usd per Bbl)	103.5
2015	'
Derivative [Line Items]	'
Volumes (Bbls)	42,649
Floor Price (in usd per Bbl)	80
Ceiling Price (in usd per Bbl)	93.25

Derivative_Contracts_Details_C1

Derivative Contracts (Details) - Commodity Derivative Positions Natural Gas Collars (Natural Gas Collars)	Mar. 31, 2014
	MMBTU
2014	'
Derivative [Line Items]	'
Volumes (MMBtu)	1,253,003
Floor Price (in usd per MMBtu)	4
Ceiling Price (in usd per MMBtu)	4.41
2015	'
Derivative [Line Items]	'
Volumes (MMBtu)	1,364,382
Floor Price (in usd per MMBtu)	4
Ceiling Price (in usd per MMBtu)	4.32

Derivative_Contracts_Details_C2

Derivative Contracts (Details) - Commodity Derivative Positions Oil Options (Oil Options, 2014)	3 Months Ended
	Mar. 31, 2014
	bbl
Oil Options | 2014	'
Derivative [Line Items]	'
Volumes (Bbls)	21,148
Floor Price (in usd per Bbl)	80

Derivative_Contracts_Details_C3

Derivative Contracts (Details) - Commodity Derivative Positions Natural Gas Options (Natural Gas Options)	3 Months Ended
	Mar. 31, 2014
	MMBTU
2014	'
Derivative [Line Items]	'
Volumes (MMBtu)	384,354
Floor Price (in usd per MMBtu)	3.5
2015	'
Derivative [Line Items]	'
Volumes (MMBtu)	798,853
Floor Price (in usd per MMBtu)	3.5
2016	'
Derivative [Line Items]	'
Volumes (MMBtu)	930,468
Floor Price (in usd per MMBtu)	3.5

Derivative_Contracts_Details_C4

Derivative Contracts (Details) - Commodity Derivative Positions Natural Gas Liquid Options (Natural Gas Liquid Options, 2014)	3 Months Ended
	Mar. 31, 2014
	bbl
Natural Gas Liquid Options | 2014	'
Derivative [Line Items]	'
Volumes (Bbls)	51,290
Average Floor Price (in usd per Bbl)	28.66

Derivative_Contracts_Details_C5

Derivative Contracts (Details) - Commodity Derivative Positions Oil Swaps (Oil Swaps)	3 Months Ended
	Mar. 31, 2014
	bbl
2014	'
Derivative [Line Items]	'
Volumes (Bbls)	9,662
Fixed Price (in usd per Bbl)	90.2
2015	'
Derivative [Line Items]	'
Volumes (Bbls)	39,411
Fixed Price (in usd per Bbl)	88.9
2016	'
Derivative [Line Items]	'
Volumes (Bbls)	36,658
Fixed Price (in usd per Bbl)	86

Derivative_Contracts_Details_C6

Derivative Contracts (Details) - Commodity Derivative Positions Natural Gas Swaps (Natural Gas Swaps)	3 Months Ended
	Mar. 31, 2014
	MMBTU
2014	'
Derivative [Line Items]	'
Volumes (MMBtu)	880,591
Avg Price (in usd per MMBtu)	4.09
2015	'
Derivative [Line Items]	'
Volumes (MMBtu)	800,573
Avg Price (in usd per MMBtu)	4.25
2016	'
Derivative [Line Items]	'
Volumes (MMBtu)	629,301
Avg Price (in usd per MMBtu)	4.37

Derivative_Contracts_Details_C7

Derivative Contracts (Details) - Commodity Derivative Positions Liquid Swaps (Natural Gas Liquid Swaps)	3 Months Ended
	Mar. 31, 2014
	bbl
2014	'
Derivative [Line Items]	'
Volumes (MMBtu)	524,133
Avg Price (in usd per MMBtu)	39.76
2015	'
Derivative [Line Items]	'
Volumes (MMBtu)	84,793
Avg Price (in usd per MMBtu)	82.74

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Fair Value Disclosures [Abstract]	'
Line of Credit Facility, Amount Outstanding	$90

Fair_Value_Measurements_Deriva

Fair Value Measurements - Derivative Assets and Obligations Measured at Fair Value (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	($3,117)	'	'	'
Fair Value, Inputs, Level 1	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
Fair Value, Inputs, Level 2	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-274	'	'	'
Fair Value, Inputs, Level 3	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-2,843	-2,517	-2,854	-112
Oil And Natural Gas Collars	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-459	'	'	'
Oil And Natural Gas Collars | Fair Value, Inputs, Level 1	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
Oil And Natural Gas Collars | Fair Value, Inputs, Level 2	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
Oil And Natural Gas Collars | Fair Value, Inputs, Level 3	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-459	'	'	'
Oil and Natural Gas Swaps	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-274	'	'	'
Oil and Natural Gas Swaps | Fair Value, Inputs, Level 1	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
Oil and Natural Gas Swaps | Fair Value, Inputs, Level 2	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-274	'	'	'
Oil and Natural Gas Swaps | Fair Value, Inputs, Level 3	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
Natural Gas and NGL Puts	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-347	'	'	'
Natural Gas and NGL Puts | Fair Value, Inputs, Level 1	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
Natural Gas and NGL Puts | Fair Value, Inputs, Level 2	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
Natural Gas and NGL Puts | Fair Value, Inputs, Level 3	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-347	'	'	'
NGL Swaps	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	-2,037	'	'	'
NGL Swaps | Fair Value, Inputs, Level 1	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
NGL Swaps | Fair Value, Inputs, Level 2	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	0	'	'	'
NGL Swaps | Fair Value, Inputs, Level 3	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'	'	'
Derivative, Fair Value, Net	($2,037)	'	'	'

Fair_Value_Measurements_Fair_V1

Fair Value Measurements - Fair Value of Allocated Derivative Assets and Liabilities (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Ending balance	($3,117)	'
Fair Value, Inputs, Level 3	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Beginning balance	-2,517	-112
Losses	-2,432	-3,057
Settlements paid	2,106	315
Ending balance	-2,843	-2,854
Change in unrealized losses included in earnings relating to derivatives still held	($702)	($2,742)

Asset_Retirement_Obligations_C

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'	'	'
Asset retirement obligation - beginning of period	$3,455	$1,510	$1,510
Liabilities incurred from acquisitions and new wells drilled	214	1,335	1,585
Revision of previous estimates	0	'	151
Current period accretion	68	29	209
Asset retirement obligation - end of period	$3,737	'	$3,455

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	1 Months Ended	3 Months Ended		12 Months Ended	24 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
Related Party Transaction [Line Items]	'	'	'	'	'
Due to Related Parties, Noncurrent	'	$350,000	'	$350,000	$350,000
Service Management Costs, Quarterly Fee	'	'	'	'	700,000
Service Management Costs	'	1,000,000	'	2,400,000	'
Prorated Fee	400,000	'	'	'	'
General and Administrative Expense	'	5,127,000	8,854,000	'	'
Chief Executive Officer	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
Common Stock, Shares, Percentage Owned by Individual	'	7.90%	'	'	'
Board of Directors Chairman	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
Ownership Percentage of Reporting Company	'	25.00%	'	'	'
Common Stock, Shares, Percentage Owned by Principal Stockholder	'	26.30%	'	'	'
Subordinated Units, Shares, Percentage Owned by Principal Stockholder	'	100.00%	'	'	'
General Partner	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
General and Administrative Expense	'	338,000	'	'	'
Chief Financial Officer	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
Ownership Percentage in Accounting Services Provider	'	31.50%	'	'	'
Professional Fees	'	$146,000	$108,000	'	'
General Partner | Chief Executive Officer	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
Ownership Percentage of Reporting Company	'	69.40%	'	'	'
Subordinated Units | Board of Directors Chairman	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
Subordinate Units, Units, Owned by Principal Stockholder	'	2,205,000	'	'	'
MidCentral Energy Services | MidCentral Energy Services | Chief Executive Officer	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
Ownership Percentage of Acquired Entity	'	36.00%	'	'	'
MidCentral Energy Services | MidCentral Energy Services | President	'	'	'	'	'
Related Party Transaction [Line Items]	'	'	'	'	'
Ownership Percentage of Acquired Entity	'	36.00%	'	'	'

Related_Party_Transactions_Sum

Related Party Transactions - Summary of Related Party Transactions (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Related Party Transaction [Line Items]	'	'
Related Party Costs	$799	$266
Producing Overhead Charges | New Dominion LLC	'	'
Related Party Transaction [Line Items]	'	'
Related Party Costs	375	170
Drilling And Completion Overhead Charges | New Dominion LLC	'	'
Related Party Transaction [Line Items]	'	'
Related Party Costs	9	17
Saltwater Disposal Fees | New Dominion LLC	'	'
Related Party Transaction [Line Items]	'	'
Related Party Costs	$415	$79

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	3 Months Ended
	Mar. 31, 2014
Loss Contingencies [Line Items]	'
Average Annual Drilling Budget Minimum	$8,200,000
Minimum	'
Loss Contingencies [Line Items]	'
Loss Contingency, Estimate of Possible Loss	10,000
Maximum	'
Loss Contingencies [Line Items]	'
Loss Contingency, Estimate of Possible Loss	$250,000

Earnings_and_Distributions_Per2

Earnings and Distributions Per Common and Subordinated Unit - (Details)	3 Months Ended
	Mar. 31, 2014
Earnings Per Share [Abstract]	'
Limited Liability (LLC) or Limited Partnership (LP), Managing Member or General Partner, Distribution Percent	1.25%

Earnings_and_Distributions_Per3

Earnings and Distributions Per Common and Subordinated Unit - Earnings Per Unit (Details) (USD $)	1 Months Ended	3 Months Ended		11 Months Ended
In Thousands, except Share data, unless otherwise specified	Feb. 11, 2013	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Numerator:	'	'	'	'
Net loss	$5,303	($1,531)	($1,397)	($6,700)
Common Stock Units	'	'	'	'
Denominator:	'	'	'	'
Weighted average units outstanding	'	9,919,926	5,395,000	'
Basic and diluted income per unit (in usd per unit)	'	($0.12)	($0.87)	'
Subordinated Units	'	'	'	'
Denominator:	'	'	'	'
Weighted average units outstanding	'	2,205,000	2,205,000	'
General Partnership Units	'	'	'	'
Denominator:	'	'	'	'
Weighted average units outstanding	'	155,102	155,102	'
Common Units	'	'	'	'
Numerator:	'	'	'	'
Net loss	'	-1,241	-4,648	'
Denominator:	'	'	'	'
Basic and diluted income per unit (in usd per unit)	'	($0.12)	($0.87)	'
General Partnership Units	'	'	'	'
Numerator:	'	'	'	'
Net loss	'	-19	-133	'
Denominator:	'	'	'	'
Basic and diluted income per unit (in usd per unit)	'	($0.12)	($0.87)	'
Subordinated Units	'	'	'	'
Numerator:	'	'	'	'
Net loss	'	($271)	($1,919)	'
Denominator:	'	'	'	'
Basic and diluted income per unit (in usd per unit)	'	($0.12)	($0.87)	'

Earnings_and_Distributions_Per4

Earnings and Distributions Per Common and Subordinated Unit - Distributions Per Unit (Details) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Dividends Payable [Line Items]	'	'
Total Distributions	$6,038	$0
Common Stock Units	'	'
Dividends Payable [Line Items]	'	'
Per Unit	$0.57	$0
Total Distributions	4,681	0
Subordinated Units	'	'
Dividends Payable [Line Items]	'	'
Total Distributions	1,268	0
General Partnership Units	'	'
Dividends Payable [Line Items]	'	'
Total Distributions	$89	$0

EquityBased_Compensation_Detai

Equity-Based Compensation (Details) (USD $)	0 Months Ended		3 Months Ended				0 Months Ended		3 Months Ended	1 Months Ended
	Feb. 13, 2013	Aug. 18, 2011	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2013	Mar. 31, 2014	Nov. 13, 2013	Nov. 12, 2013	Mar. 31, 2014	Feb. 11, 2013
					Restricted Stock	MidCentral Energy Services	MidCentral Energy Services	MidCentral Energy Services	Common Stock	New Source Energy Partners LP
						Restricted Stock	Select MCE Employees	Select MCE Employees	Select MCE Employees
							Restricted Stock	Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'	'	'	'	'
Stock Issued During Period, Shares, Restricted Stock Award, Gross	367,500	2,900,000	'	'	'	'	'	'	'	'
Investment Owned, Restricted, Carrying Value Per Unit at Date of Balance Sheet (in Dollars per Item)	20	'	'	'	'	'	'	'	'	'
Allocated equity-based compensation of parent	'	'	'	'	$7,700,000	'	'	'	'	'
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	'	'	'	'	'	'	99,768	'	'	'
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	'	'	'	'	'	'	'	2,300,000	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'	'	'	'	'	'3 years	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Days After Calendar Year that Forfeited Shares Are Issued to Prior Owners	'	'	'	'	'	'45 days	'	'	'	'
Unit Compensation Funded By Unitholders	'	'	258,000	'	'	'	'	'	260,000	'
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	'	'	1,900,000	'	'	'	'	'	'	'
Restricted Stock Shares Vesting Within 1 Year Of Issue Date	'	1,000,000	'	'	'	'	'	'	'	'
Restricted Stock Shares Vesting Within 2 Years Of Issue Date	'	700,000	'	'	'	'	'	'	'	'
Restricted Stock Shares Vesting Upon Completion Of IPO	'	1,200,000	'	'	'	'	'	'	'	'
Equity-based compensation	'	'	$258,000	$7,738,000	'	'	'	'	'	$400,000

EquityBased_Compensation_Detai1

Equity-Based Compensation (Details) - Equity-Based Compensation Expense (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Equity-based compensation	$258	$7,738
New Source Energy	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Allocated equity-based compensation of parent	$0	$400

Contingent_Consideration_Detai

Contingent Consideration (Details) (USD $)	3 Months Ended				3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014	Nov. 12, 2013	Mar. 31, 2014	Mar. 31, 2014	Jan. 31, 2014
			MidCentral Energy Services	MidCentral Energy Services	Southern Dome	CEU Paradigm	CEU Paradigm
					Boe	Boe
Business Acquisition [Line Items]	'	'	'	'	'	'	'
Business Combination, Contingent Consideration Arrangements, Cap on Aggregate Total Consideration Paid	'	'	$120,000,000	'	'	'	'
Business Combination, Contingent Consideration, Liability	6,753,000	6,320,000	6,800,000	6,300,000	0	0	0
Business Combination, Contingent Consideration, Average Daily Production of Oil Well Required for Additional Consideration	'	'	'	'	383.5	566	'
Business Combination, Contingent Consideration Arrangements, Change in Fair Value of Contingent Consideration, Liability	$433,000	'	'	'	$1,600,000	'	'

Contingent_Consideration_Recon

Contingent Consideration - Reconciliation of Acquisition Related Accrued Earnouts (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Jan. 31, 2014
			CEU Paradigm	CEU Paradigm
Business Acquisition, Contingent Consideration [Roll Forward]	'	'	'	'
Accrued earnout liability as of December 31, 2013	$6,320,000	'	'	$0
Acquisition date fair value of contingent consideration - CEU Acquisition	433,000	0	0	'
Change in fair value of contingent consideration	433,000	'	'	'
Payment of contingent consideration	0	'	'	'
Accrued earnout liability as of March 31, 2014	$6,753,000	'	$0	$0

Business_Segment_Information_D

Business Segment Information (Details)	3 Months Ended
	Mar. 31, 2014
	segment
Segment Reporting [Abstract]	'
Number of Operating Segments	2

Business_Segment_Information_S

Business Segment Information - Summary of Segment Operating Activities (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Segment Reporting Information [Line Items]	'	'
Revenues	$27,427	$9,360
Operating costs	-9,948	-3,400
Segment margin	17,479	5,960
Capital expenditures	18,086	112
Depreciation, Depletion and Amortization	9,279	3,195
Exploration and Production	'	'
Segment Reporting Information [Line Items]	'	'
Revenues	18,851	9,360
Operating costs	-5,382	-3,400
Segment margin	13,469	5,960
Capital expenditures	17,275	112
Depreciation, Depletion and Amortization	5,819	3,195
Oilfield Services	'	'
Segment Reporting Information [Line Items]	'	'
Revenues	8,576	0
Operating costs	-4,566	0
Segment margin	4,010	0
Capital expenditures	811	0
Depreciation, Depletion and Amortization	$3,460	$0

Business_Segment_Information_R

Business Segment Information - Reconciliation of Segment Profits to Consolidated Statements of Operations (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Segment Reporting [Abstract]	'	'
Gross Profit	$17,479	$5,960
Depreciation, depletion and amortization	-9,279	-3,195
General and administrative	-5,127	-8,854
Accretion	-68	-29
Operating income (loss)	$3,005	($6,118)

Subsequent_Events_Details

Subsequent Events (Details) (Subsequent Event, USD $)	0 Months Ended
In Millions, except Share data, unless otherwise specified	Apr. 29, 2014	Apr. 08, 2014
Subsequent Event [Line Items]	'	'
Partners' Capital Account, Aggregate Amount of Units Registered to Sell	'	$500
Partners' Capital Account, Proceeds from Public Sale used in Repayment of Debt	5	'
Common Units	'	'
Subsequent Event [Line Items]	'	'
Partners' Capital Account, Units, Sold in Public Offering	3,450,000	'
Partners' Capital Account, Public Sale Of Units, Unit Price	$23.25	'
Partners' Capital Account, Public Sale of Units Net of Offering Costs	75.8	'
Partners' Capital Account, Public Sale of Units, Underwriters' Fees	3.6	'
Partners' Capital Account, Public Sale of Units, Offering Costs	$0.80	'