New Source Energy Partners (NSLP) 10-Q 11 May 15 2015 Q1 Quarterly report Financial data

Document_And_Entity_Informatio

Document And Entity Information	3 Months Ended
	Mar. 31, 2015	6-May-15
Document Information [Line Items]
Entity Registrant Name	New Source Energy Partners L.P.
Document Type	10-Q
Current Fiscal Year End Date	-19
Amendment Flag	FALSE
Entity Central Index Key	1560443
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	31-Mar-15
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Common Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		16,558,236
Subordinated Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		2,205,000

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Thousands, unless otherwise specified
Current assets:
Cash	$1,531		$5,504
Restricted cash	85		350
Accounts receivable, net	24,404		31,919
Accounts receivable-related parties, net	5,519		4,946
Derivative contracts	7,292		8,248
Inventory	4,564		4,236
Other current assets	2,850		2,489
Total current assets	46,245		57,692
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	333,205		332,413
Less: Accumulated depreciation, depletion, amortization, and impairment	-201,548		-153,734
Total oil and natural gas properties, net	131,657		178,679
Property and equipment, net	72,744		68,886
Intangible assets, net	51,211		56,377
Goodwill	9,315		9,315
Derivative contracts	1,659		1,818
Other assets	2,702		2,779
Total assets	315,533	[1]	375,546
Current liabilities:
Accounts payable and accrued liabilities	16,152		15,326
Accounts payable-related parties	266		2,318
Factoring payable	11,352		13,152
Contingent consideration payable	11,572		11,572
Other current liabilities	122		113
Current portion of long-term debt	12,277		11,825
Total current liabilities	51,741		54,306
Long-term debt	94,804		95,218
Contingent consideration payable	10,633		10,801
Asset retirement obligations	3,639		3,568
Other liabilities	252		339
Total liabilities	161,069		164,232
Commitments and contingencies (Note 12)
Unitholders' equity:
Common units 16,403,134 units issued and outstanding at March 31, 2015 and 16,160,381 units issued and outstanding at December 31, 2014	180,014		231,510
Common units held in escrow	-4,680		-6,955
Subordinated units 2,205,000 units issued and outstanding at March 31, 2015 and December 31, 2014	-35,845		-28,717
General partner's units 155,102 units issued and outstanding at March 31, 2015 and December 31, 2014	-2,445		-1,944
Total New Source Energy Partners L.P. unitholders' equity	137,044		193,894
Noncontrolling interest	17,420		17,420
Total unitholders' equity	154,464		211,314
Total liabilities and unitholders' equity	$315,533		$375,546
[1]	Exploration and Production includes impairment of oil and natural gas properties of $43.1 million as discussed in Note 10 "Property, Plant and Equipment."

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Unaudited) (Parentheticals)	Mar. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common units outstanding (in Shares)	16,403,134	16,160,381
Common units issued (in Shares)	16,403,134	16,160,381
Subordinated units outstanding (in Shares)	2,205,000	2,205,000
Subordinated units issued (in Shares)	2,205,000	2,205,000
General partner's capital units outstanding (in Shares)	155,102	155,102
General partner's capital units, issued (in Shares)	155,102	155,102

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Operations (Unaudited) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues:
Oil sales	$1,692	$3,947
Natural gas sales	1,843	5,367
NGL sales	3,032	9,537
Oilfield services	31,550	8,576
Total revenues	38,117	27,427
Operating costs and expenses:
Oil, natural gas and NGL production	4,055	4,503
Production taxes	311	879
Cost of providing oilfield services	23,059	4,566
Depreciation, depletion and amortization	12,347	9,279
Accretion	74	68
Impairment of oil and natural gas properties	43,119	0
General and administrative	12,234	5,560
Total operating costs and expenses	95,199	24,855
Operating (loss) income	-57,082	2,572
Other income (expense):
Interest expense	-1,348	-969
Gain (loss) on derivative contracts, net	1,224	-3,132
Other income (expense)	34	-2
Net loss	-57,172	-1,531
Less: net income attributable to noncontrolling interest	0	0
Net loss attributable to New Source Energy Partners L.P.	-57,172	-1,531
General Partnership Units [Member]
Other income (expense):
Net loss	-470
Net loss per unit:
Basic and diluted income per unit (in usd per unit)	($3.03)	($0.12)
Subordinated Units [Member]
Other income (expense):
Net loss	-7,128
Net loss per unit:
Basic and diluted income per unit (in usd per unit)	($3.23)	($0.12)
Common Units [Member]
Other income (expense):
Net loss	($49,574)
Net loss per unit:
Basic and diluted income per unit (in usd per unit)	($3.03)	($0.12)

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Unitholders' Equity (Unaudited) (USD $)	Total	Common [Member]	Subordinated [Member]	General Partnership [Member]	Noncontrolling Interest [Member]
In Thousands, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2014	$211,314	$224,555	($28,717)	($1,944)	$17,420
Beginning Balance (in units) at Dec. 31, 2014		16,160,381	2,205,000	155,102
Increase (Decrease) in Partners' Capital [Roll Forward]
Acquisition from unitholder	-227	-227
Equity-based compensation (in units)		242,753
Equity-based compensation	3,861	3,861
Distributions to unitholders	-3,312	-3,281		-31
Net loss	-57,172	-49,574	-7,128	-470
Ending Balance at Mar. 31, 2015	$154,464	$175,334	($35,845)	($2,445)	$17,420
Ending Balance (in units) at Mar. 31, 2015		16,403,134	2,205,000	155,102

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Cash Flow (Unaudited) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash Flows from Operating Activities:
Net loss	($57,172)	($1,531)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	12,347	9,279
Impairment of oil and natural gas properties	43,119	0
Accretion	74	68
Amortization of deferred loan costs	169	0
Equity-based compensation	3,861	258
Change in fair value of contingent consideration	0	433
(Gain) loss on derivative contracts, net	-1,224	3,132
Cash received (paid) on settlement of derivative contracts	2,339	-2,429
Changes in operating assets and liabilities:
Accounts receivable	8,861	-5,117
Other current assets and other assets	-655	-454
Accounts payable and accrued liabilities	-3,027	2,770
Net cash provided by operating activities	8,692	6,409
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	0	-6,900
Additions to oil and natural gas properties	-879	-10,372
Additions to other property and equipment	-5,291	-814
Net cash used in investing activities	-6,170	-18,086
Cash Flows from Financing Activities:
Proceeds from borrowings	3,020	13,872
Payments on borrowings	-4,403	-245
Payments for deferred loan costs	0	-267
Payments on factoring payable, net	-1,800	-1,907
Payments of offering costs	0	-100
Distribution to unitholders	-3,312	-6,038
Net cash (used in) provided by financing activities	-6,495	5,315
Net change in cash and cash equivalents	-3,973	-6,362
Cash and cash equivalents, beginning of period	5,504	7,291
Cash and cash equivalents, end of period	1,531	929
Supplemental Cash Flow Information:
Cash paid for interest	1,149	999
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation	0	214
Decrease in accrued capital expenditures	-253	0
Common units issued in connection with acquisitions	0	-11,620
Acquisition of property and equipment by financing	$1,200	$2,329

Basis_of_Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation
	Nature of Business. We are a Delaware limited partnership formed in October 2012 to own and acquire oil and natural gas properties in the United States. We are engaged in the production of onshore oil and natural gas properties that extend across conventional resource reservoirs in east-central Oklahoma. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation. In addition, we are engaged in oilfield services through our oilfield services subsidiaries. Our oilfield services business provides wellsite services during the drilling and completion stages of a well, including full service blowout prevention installation, pressure testing services, including certain ancillary equipment necessary to perform such services, well testing and flowback services to companies in the oil and natural gas industry primarily in Oklahoma, Texas, New Mexico, Kansas, Pennsylvania, Ohio and West Virginia.
	Principles of Consolidation. The unaudited condensed consolidated financial statements include the accounts of the Partnership and its wholly owned and majority owned subsidiaries. Noncontrolling interest represents third-party ownership interest in a majority owned subsidiary of the Partnership and is included as a component of equity in the consolidated balance sheet and consolidated statement of unitholders' equity. All significant intercompany accounts and transactions have been eliminated in consolidation.
	Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2014 have been derived from the audited financial statements contained in the Partnership’s 2014 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 2014 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 accompanying 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 2014 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 2014 Form 10-K.
	Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Partnership's previously reported results of operations.
	Use of Estimates. The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed and asset retirement obligations. Actual results could differ from those estimates.
	Recently Issued Accounting Standard. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, ("ASU 2014-09"), which revises the guidance on revenue recognition by providing a single, principles-based method for companies to use to account for revenue arising from contracts with customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard permits the use of either the retrospective or cumulative effect transition method. ASU 2014-09 is effective for fiscal years beginning after December 15, 2016. Early application is not permitted. We are in the process of assessing which transition method we will apply and the potential impact of ASU 2014-09 on the Partnership's financial statements. In April 2015, the FASB voted to propose to defer the effective date by one year.
	In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We are currently evaluating the effect, if any, the guidance will have on our related disclosures.
	In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.
	In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction from the carrying amount of the debt. The new standard does not change the recognition and measurement of debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect the guidance will have on our consolidated financial statements and related disclosures.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions
	The Partnership completed acquisitions during 2014, as described below. The acquisitions of Erick Flowback Services LLC ("EFS"), Rod's Production Services, L.L.C. ("RPS") and MidCentral Completion Services, LLC ("MCCS") expanded the Partnership's oilfield services segment. The acquisition of MCCS was with related parties. See Note 9 "Related Party Transactions." In 2014, we also acquired working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma to expand the Partnership's exploration and production segment.
	The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy as described in Note 6 "Fair Value Measurements." Fair value may be estimated using comparable market data, a discounted cash flow method, or another method as discussed below. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of applicable sales estimates, operational costs and a risk-adjusted discount rate. 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. Fair value of MCCS' inventory acquired was determined based on a comparative sales approach. Fair value for intangible assets acquired was primarily determined using a discounted cash flow model or multi-period excess earnings model under the income approach, which factors in discount rates, probability factors and forecasts. The fair values of property, plant and equipment acquired were primarily based on a cost approach using an indirect cost methodology to determine replacement cost. The inputs, as noted above, used to determine fair value 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. Carrying value for current assets and liabilities acquired is typically representative of fair value due to their short term nature.
	CEU Acquisition. On January 31, 2014, we completed the acquisition of 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") for approximately $17.1 million, net of purchase price adjustments (the "CEU Acquisition").
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition, net of purchase price adjustments, is as follows (in thousands):
	Consideration:
	Cash	$	5,503
	Fair value of common units granted (1)	11,621
	Contingent consideration (2)	—
	Total fair value of consideration	$	17,124
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	17,306
	Asset retirement obligations	(182		)
	Total net assets	$	17,124
	__________
	-1	The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition).
	-2	The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU.
	MCCS Acquisition. On June 26, 2014, we exercised the option granted in connection with the acquisition of MCE in November 2013 to acquire 100% of the equity interest in MCCS, an oilfield services company that specializes in providing services, primarily installation and pressure testing, to oil and natural gas exploration and production companies (the "MCCS Acquisition").
	Total consideration for the MCCS Acquisition is as follows (in thousands):
	Consideration:
	Fair value of common units granted (1)	$	789
	Contingent consideration (2)	4,057
	Noncontrolling interest (3)	831
	Total fair value of consideration	$	5,677
	__________
	-1	The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition).
	-2	The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 12 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
	-3	As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.
	The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Cash	$	109
	Accounts receivable	524
	Inventory	2,035
	Other current assets	14
	Property and equipment	107
	Intangible asset (1)	1,700
	Goodwill (2)	3,382
	Other assets	28
	Total assets acquired	7,899
	Accounts payable and accrued liabilities	(1,431		)
	Long-term debt	(791		)
	Total liabilities assumed	(2,222		)
	Net assets acquired	$	5,677
	__________
	-1	Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.
	-2	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS' business.
	Since the Chairman and Chief Executive Officer of our general partner, Kristian B. Kos, through his control over our general partner, controls the Partnership and also owned 50% of the equity interest in MCCS, the MCCS Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 50% equity interest in MCCS acquired from Mr. Kos at his equity method carrying basis, which was $0.1 million as of June 26, 2014. The Partnership remeasured the 50% interest to determine the acquisition-date fair value and recognized a corresponding gain of $2.3 million on investment in acquired business.
	Services Acquisition. On June 26, 2014, the Partnership acquired 100% of the outstanding membership interests in EFS and 100% of the outstanding membership interests in RPS for total consideration of approximately $113.2 million (the "Services Acquisition"). EFS and RPS, which are affiliated entities, are oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry.
	Total consideration for the Services Acquisition is as follows (in thousands):
	Consideration:
	Cash	$	57,348
	Fair value of common units granted (1)	33,106
	Common units granted for the benefit of EFS and RPS employees (2)	724
	Contingent consideration (3)	21,984
	Total fair value of consideration	$	113,162
	__________
	-1	The fair value of the unit consideration was based upon 1,411,777 common units valued at $23.45 per unit (closing price on the date of the acquisition).
	-2	The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 7 "Equity" for additional discussion of phantom units.
	-3	The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 12 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.
	The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Cash	$	1,668
	Accounts receivable	22,674
	Other current assets	620
Property and equipment	43,853
Intangible assets (1)	68,700
Goodwill (2)	14,224
Total assets acquired	151,739
Accounts payable and accrued liabilities	(5,937		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,577		)
Net assets acquired	$	113,162
__________
-1	Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years. Non-compete agreements were valued based on an income approach and are amortized over the agreement period.
-2	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS and RPS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships. Goodwill has been allocated to the oilfield services segment.
Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the three months ended March 31, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the three months ended March 31, 2014 have been prepared by adjusting the historical results of the Partnership to include the historical results of the 2014 Material Acquisitions through the dates of acquisition and estimates of the effect of these transactions on the combined results. In addition, pro forma adjustments have been made assuming the units issued as consideration for these acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund the Services Acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.
	Three Months Ended March 31, 2014
	(in thousands, except per unit amounts)
Revenue	$	60,285
Net income attributable to New Source Energy Partners L.P.	$	2,107
Net income per common unit:
Basic	$	0.13
Diluted	$	0.13
The amount of revenues and revenues in excess of direct operating expenses included in the accompanying unaudited condensed consolidated statements of operations for the three months ended March 31, 2014 generated by the oil and natural gas properties acquired in the CEU Acquisition are shown in the table below. Direct operating expenses include lease operating expenses and production and other taxes and do not reflect certain expenses, such as general and administrative; 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
	(in thousands)
Revenue		$	1,883
Excess of revenue over direct operating expenses		$	1,119

Debt

Debt	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Debt	Debt
	The Partnership's debt consists of the following (in thousands):
		31-Mar-15		31-Dec-14
	Credit facility	$	84,000	$	83,000
	Notes payable	19,652		20,424
	Line of credit	3,429		3,619
	Total debt	107,081		107,043
	Less: current maturities of long-term debt	12,277		11,825
	Long-term debt	$	94,804	$	95,218
	Senior Secured Revolving Credit Facility
	The Partnership has a senior secured revolving credit facility (the "credit facility") that is available to be drawn on subject to limitations based on its terms and certain financial covenants described below. As of March 31, 2015, 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 financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of its subsidiaries. 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) 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%. As of March 31, 2015, the Partnership was in compliance with all covenants under the credit facility.
	Our credit facility is subject to a borrowing base which is generally set by the bank semi-annually on April 1 and October 1 of each year. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. At March 31, 2015, the borrowing base under the credit facility was $90.0 million. In April 2015, our borrowing base was decreased from $90.0 million to $84.0 million and the semi-annual redetermination was moved to May 2015. On May 8, 2015, the borrowing base was reduced to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. As outstanding borrowings under our credit facility exceeded the new borrowing base resulting from the redetermination, we are required to eliminate this excess. On May 8, 2015, the Partnership remitted payment of $41.0 million which resulted in an outstanding balance under our credit facility of $43.0 million.
	See Note 14 "Subsequent Events" for additional discussion of amendments to our credit facility 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) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) 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. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At March 31, 2015 and December 31, 2014, the average annual interest rate on borrowings outstanding under the credit facility was 3.51% and 3.44%, respectively.
	Notes Payable
	MCES Notes Payable. The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. The notes range from 12 to 60 months in duration with maturity dates from August 2015 through March 2019 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. The Partnership had $6.5 million outstanding, of which $3.2 million was current, under the MCES notes payable as of March 31, 2015.
	EFS Loan Agreement. In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on EFS' existing notes payable, which were originally set to mature on June 26, 2015. In March 2015, we refinanced EFS' notes payable to extend the maturity date to March 2018. The balance on the note payable at March 31, 2015 was $11.7 million, of which $4.2 million was current.
	The note payable has a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at March 31, 2015, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The note payable is collateralized by various assets of the parties to the agreement and guaranteed by MCE. The Partnership is required to maintain a reserve bank account into which $0.3 million shall be deposited quarterly beginning after the initial deposit of $0.5 million on September 30, 2015, and used to fund an additional annual payment on September 30th of each year during the term of the note.
	The EFS loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0, (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $1.0 million by June 30, 2015 increasing to at least $3.5 million by October 1, 2015, in each case as more fully described in the loan agreement. As of March 31, 2015, EFS and RPS were in compliance with the covenants under the loan agreement.
	MCES Promissory Notes. On January 9, 2015 and February 24, 2015, MCES issued promissory notes totaling approximately $1.4 million, to acquire land from entities owned 50% by Mr. Kos, Chief Executive Officer of our general partner, and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner. Both promissory notes bear interest at prime plus one percent and are payable, including all accrued interest, on December 31, 2015. No payments are due prior to maturity. See Note 9 "Related Party Transactions" for additional discussion of the related party land transactions.
	Line of Credit
	In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. Interest only payments are due monthly with the line of credit which was set to mature in May 2015, but was extended to mature in June 2015. Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at March 31, 2015. The line of credit is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. Based on the outstanding balance of $3.4 million, there was $0.6 million of available borrowing capacity at March 31, 2015.
	The line of credit contains a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of March 31, 2015, MCES was in compliance with this covenant under the line of credit.

Factoring_Payable

Factoring Payable	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Factoring Payable	Factoring Payable
	The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of MCES. The outstanding balance was paid and the agreement was terminated in February 2014 when MCES established its line of credit. See Note 3 "Debt" for discussion of MCES' line of credit.
	In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 3% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not collected within 90 days, the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $11.4 million as of March 31, 2015.

Derivative_Contracts

Derivative Contracts	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Contracts	Derivative Contracts
	Due to the volatility of commodity prices, the Partnership periodically enters into derivative contracts for a portion of its oil, natural gas and NGL production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of derivative contracts limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and NGLs, it also reduces the Partnership’s potential exposure to adverse price movements. The Partnership’s derivative contracts apply to only a portion of its expected production, provide only partial price protection against declines in market prices and limit the Partnership’s potential gains from future increases in market prices. Changes in the derivatives' fair values are recognized in earnings since the Partnership has elected not to designate its derivative contracts as hedges for accounting purposes.
	At March 31, 2015, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:
	Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.
	Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.
	Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the market price and the fixed price.
	Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
	The following tables present our derivative instruments outstanding as of March 31, 2015:
	Oil collars		Volumes		Floor Price				Ceiling Price
			(Bbls)
	2015		30,072		$	80			$	93.25
	Oil collars - three way		Volumes		Sold Put				Purchased Put			Ceiling Price
			(Bbls)
	2015		27,500		$	77.5			$	92.5		$	102.6
	Oil fixed price swaps		Volumes (Bbls)		Weighted Average Fixed Price
	2015		30,080		$	88.9
	2016		36,658		$	86
	Natural gas collars		Volumes		Floor Price				Ceiling Price
			(MMBtu)
	2015		976,356		$	4			$	4.32
	Natural gas put options		Volumes		Floor Price
			(MMBtu)
	2015		620,040		$	3.5
	2016		930,468		$	3.5
	Natural gas fixed price swaps		Volumes		Weighted Average Fixed Price
			(MMBtu)
	2015		582,451		$	4.25
	2016		629,301		$	4.37
	NGL fixed price swaps		Volumes		Weighted Average Fixed Price
			(Bbls)
	2015		62,213		$	75.18
	By using derivative instruments to mitigate exposures to changes in commodity prices, the Partnership exposes itself to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. The Partnership nets derivative assets and liabilities for counterparties where it has a legal right of offset. 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 summarizes our derivative contracts on a gross basis and the effects of netting assets and liabilities for which the right of offset exists (in thousands):
	31-Mar-15		Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset				Net Amounts Presented
	Assets:
	Commodity derivatives - current assets		$	7,292		$	—			$	7,292
	Commodity derivatives - long-term assets		1,659			—				1,659
	Total		$	8,951		$	—			$	8,951
	Liabilities:
	Commodity derivatives - current liabilities		$	—		$	—			$	—
	Commodity derivatives - long-term liabilities		—			—				—
	Total		$	—		$	—			$	—
	31-Dec-14		Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset				Net Amounts Presented
	Assets:
	Commodity derivatives - current assets		$	8,309		$	(61	)		$	8,248
	Commodity derivatives - long-term assets		1,818			—				1,818
	Total		$	10,127		$	(61	)		$	10,066
	Liabilities:
	Commodity derivatives - current liabilities		$	61		$	(61	)		$	—
	Commodity derivatives - long-term liabilities		—			—				—
	Total		$	61		$	(61	)		$	—
	See Note 6 "Fair Value Measurements" for additional information on the fair value measurement of the Partnership's derivative contracts.
	The following table presents gain (loss) on our derivative contracts as included in the accompanying unaudited statements of operations for the three months ended March 31, 2015 and 2014 (in thousands):
			Three Months Ended March 31,
			2015			2014
	Total gain (loss) on derivative contracts, net (1)		$	1,224		$	(3,132	)
	__________
	-1	Included in gain (loss) on derivative contracts for the three months ended March 31, 2015 and 2014 are net cash receipts (payments) upon contract settlement of $2.3 million and $(2.4) million, respectively.

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements
	We measure and report certain assets and liabilities at fair value and classify and disclose our fair value measurements based on the levels of the fair value hierarchy, as described below:
	Level 1:     Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
	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.
	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).
	Assets and liabilities that are measured at fair value 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, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
	Level 2 Fair Value Measurements
	Derivative contracts. The fair values of our commodity collars, put options and fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. 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.
	Level 3 Fair Value Measurements
	Derivative contracts. The fair values of our natural gas collars, natural gas and NGL put options and NGL fixed price swaps at March 31, 2014 were based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness. The significant unobservable inputs used in the fair value measurement of our natural gas and NGL put options and NGL fixed price swaps were the estimated probability of exercise and the estimate of NGL futures prices. Significant increases (decreases) in the probability of exercise and NGL futures prices could result in a significantly higher (lower) fair value measurement.
	Contingent consideration. As discussed in Note 12 "Commitments and Contingencies," the Partnership agreed to pay additional consideration on certain acquisitions if specific target metrics are met. The fair value of the contingent consideration resulting from these acquisitions is based on the present value of estimated future payments, using various inputs, including forecasted EBITDA metrics and the probability that targets for additional payout will be met. Significant increases (decreases) in the probability of meeting target payout levels could result in a significantly higher (lower) fair value measurement.
	The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis (in thousands):
	31-Mar-15		Fair Value Measurements
	Description		Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)		Unobservable Inputs (Level 3)			Total Carrying Value
	Oil and natural gas collars		$	—		$	2,436	$	—		$	2,436
	Oil, natural gas and NGL put options		—			1,035		—			1,035
	Oil, natural gas and NGL fixed price swaps		—			5,480		—			5,480
	Total		$	—		$	8,951	$	—		$	8,951
	31-Dec-14		Fair Value Measurements
	Description		Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)		Unobservable Inputs (Level 3)			Total Carrying Value
	Oil and natural gas collars		$	—		$	2,411	$	—		$	2,411
	Oil, natural gas and NGL put options		—			1,405		—			1,405
	Oil, natural gas and NGL fixed price swaps		—			6,250		—			6,250
	Contingent consideration		—			—		(23,330		)	(23,330		)
	Total		$	—		$	10,066	$	(23,330	)	$	(13,264	)
	The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2014 (in thousands):
			Three Months Ended March 31, 2014
	Beginning balance		$	(2,517	)
	Loss on derivative contracts		(2,432		)
	Cash paid upon settlement		2,106
	Ending balance (1)		$	(2,843	)
	Unrealized losses included in earnings relating to derivatives held at period end		$	(702	)
	__________
	-1	Fair values related to the Company’s natural gas collars, natural gas and NGL put options and NGL fixed price swaps were transferred from Level 3 to Level 2 in the second quarter of 2014 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value.
	See Note 5 "Derivative Contracts" for additional discussion of our derivative contracts.
	Fair Value of Financial Instruments
	Credit Facility. The carrying amount of the credit facility of $84.0 million and $83.0 million as of March 31, 2015 and December 31, 2014, respectively, approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings.
	Notes Payable. The carrying value of our notes payable of $19.7 million and $20.4 million at March 31, 2015 and December 31, 2014 approximated fair value based on rates applicable to similar instruments.
	The credit facility and notes payable are classified as a Level 2 item within the fair value hierarchy.
	Fair Value on a Non-Recurring Basis
	The Partnership performs valuations on a non-recurring basis primarily as it relates to the consideration, assets acquired, and liabilities assumed related to acquisitions. See Note 2 "Acquisitions" and Note 12 "Commitments and Contingencies" for discussion of these valuations.

Equity

Equity	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Equity	Equity
	Equity Offerings
	Issuance for Acquisitions. In 2014, we issued 1,964,957 of common units to satisfy the equity portion of the consideration paid in the CEU Acquisition, the MCCS Acquisition, and the Services Acquisition. See Note 2 "Acquisitions" for additional discussion of these transactions.
	Equity Offering. In April 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 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 used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes.
	Distributions
	Distributions are declared and distributed within 45 days following the end of each quarter. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the three months ended March 31, 2015 and 2014, as shown in the following table (in thousands):
	Distributions		Payable Date		Distribution per Unit			Common Units		Subordinated Units		General Partner Units		Total
	2015
	First Quarter		15-May-15		$	0.2		$	3,312	$	—	$	—	$	3,312
	2014
	First Quarter		15-May-14		$	0.58		$	7,852	$	1,279	$	90	$	9,221
	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. No such incentive distributions were made to our general partner as quarterly distributions declared by the board of directors for the first quarters of 2015 and 2014 did not exceed the specified targets. The distribution per common unit of $0.20 in the first quarter of 2015 is below the minimum quarterly distribution ("MQD") per the partnership agreement before the subordinated units receive distributions. Additionally, the subordinated units are not entitled to receive distributions until the common units receive an amount equal to the MQD and the cumulative arrearages which is approximately $5.3 million at March 31, 2015. The subordination period ends on the first business day after all units have received the MQD for each of four consecutive quarters ending on or after December 31, 2015, or as otherwise provided for under the partnership agreement.
	See Note 14 "Subsequent Events" for discussion of distribution declared in May 2015.
	Noncontrolling Interest
	As part of the MCE Acquisition, certain former owners of MCE retained 100 Class B Units in MCE. The MCE partnership agreement provides that the Class B Units have the right to receive an increasing percentage (15%, 25% and 50%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved based on results of MCES and MCCS. Target distribution levels are adjusted, as applicable and in accordance with the MCE partnership agreement, under certain circumstances. As these Class B Units are not held by the Partnership, they are presented as noncontrolling interest in the accompanying unaudited condensed consolidated financial statements. Any distribution to the Class B Units will be recognized in the period earned and recorded as a reduction to net income attributable to the Partnership.
	As a result of the MCCS Acquisition, the specified target distribution levels for the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders were adjusted for the contribution of MCCS to MCE by the Partnership as provided for in the MCE partnership agreement. The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels, as adjusted based on the MCCS Acquisition.
						Marginal Percentage Interest in
						Distributions
		Total Quarterly Distributions per MCE Unit				MCE Class A Unitholders (the Partnership)	MCE Class B Unitholders
	Minimum Quarterly Distribution	$16,116				100%	—%
	First Target Distribution	$18,533	to	$20,144		85%	15%
	Second Target Distribution	$20,145	to	$24,173		75%	25%
	Third Target Distribution and Thereafter	$24,174	and above			50%	50%
	No distributions were due to the MCE Class B unitholders for the first quarter of 2015 or 2014.
	Equity Compensation
	We may grant awards of the Partnership's common units to employees under the Partnership's Long-Term Incentive Plan ("LTIP") or Fair Market Value Purchase Plan ("FMVPP"). In the first quarter of 2015, we granted 242,753 common units under the LTIP. Of these common units granted, 219,439 vested immediately or had accelerated vesting, which resulted in $1.5 million of equity-based compensation expense during the three months ended March 31, 2015.
	Phantom Units. In conjunction with the Services Acquisition, the Partnership granted 432,038 phantom units, which represent the right to receive common units or cash equal to the value of the associated common units, to employees of EFS and RPS under the FMVPP. The phantom units vest over a period not to exceed 2 years. Although the phantom unit grants may be settled in either common units or cash at the holder's election, the settlement of the phantom units upon vesting will be made from a transfer or sale of the associated common units that were issued to an escrow account, reflected as contra equity on the accompanying unaudited condensed consolidated balance sheet, in conjunction with the Services Acquisition. As a result, the 401,171 phantom units valued at $10.1 million with a service requirement were measured at fair market value of the Partnership’s common units on the grant date and are being expensed over the vesting period in accordance with accounting guidance for equity compensation. In the first quarter of 2015, $2.3 million was expensed for these phantom units, including $0.9 million related to accelerated phantom unit vesting.
	For the three months ended March 31, 2015 and 2014, the Partnership recorded total equity-based compensation expense of $3.9 million and $0.3 million, respectively.

Earnings_per_Unit

Earnings per Unit	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Earnings per Unit	Earnings per Unit
	The Partnership’s net income is allocated to the common, subordinated and general partner unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the Partnership’s LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period.
	We present earnings per unit regardless of whether such earnings would or could be distributed under the terms of our partnership agreement. Accordingly, the reported earnings per unit is not indicative of potential cash distributions that may be made based on historical or future earnings. Basic and diluted net income per unit is calculated by dividing net income attributable to each class of unit by the weighted average number of units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. During the three months ended March 31, 2015, LTIP awards of 32,542 common units were excluded from the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of March 31, 2014. Therefore, basic and diluted earnings per unit are the same for the three months ended March 31, 2014.
	Basic and diluted earnings per unit for the three months ended March 31, 2015 and 2014 were computed as follows (in thousands, except per unit amounts):
		Three Months Ended
		March 31, 2015
		Common Units			Subordinated Units			General Partner
	Net loss	$	(49,574	)	$	(7,128	)	$	(470	)
	Weighted average units outstanding	16,346			2,205			155
	Basic and diluted loss per unit	$	(3.03	)	$	(3.23	)	$	(3.03	)
		Three Months Ended
		March 31, 2014
		Common Units			Subordinated Units			General Partner
	Net loss	$	(1,241	)	$	(271	)	$	(19	)
	Weighted average units outstanding	9,920			2,205			155
	Basic and diluted loss per unit	$	(0.12	)	$	(0.12	)	$	(0.12	)

Related_Party_Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions
	Ownership. The Partnership is controlled by our general partner. As of March 31, 2015, our general partner was owned 69.4% by Kristian Kos, the Chairman and Chief Executive Officer of our general partner, and 25.0% by David J. Chernicky, the former Chairman of the board of directors of our general partner. Mr. Kos beneficially owns approximately 5.0% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through Deylau, LLC ("Deylau"), an entity he controls. As of March 31, 2015, Mr. Chernicky beneficially owned approximately 15.6% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through NSEC and Scintilla, entities that he controls. In addition, Mr. Chernicky beneficially owns 100% of the 2,205,000 subordinated units through his control of NSEC. As a result of Mr. Chernicky's ownership of the Partnership and his ownership of all of the membership interests in New Dominion, which operates all of the Partnership's oil and natural gas properties, transactions with New Dominion are deemed to be with a related party. See Note 14 "Subsequent Events" for discussion of the transfer of interest in our general partner in April 2015.
	New Dominion. New Dominion is an exploration and production operator, which 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. In addition to the various development agreements, the Partnership, along with other working interest owners, is a party to an agreement with New Dominion in which we reimburse New Dominion for our proportionate share of costs incurred to construct a gas gathering system. In return, we own a portion of such gas gathering system, which facilitates the transportation of our production in the Greater Golden Lane field to the gas processing plant.
	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 was approximately $0.2 million as of March 31, 2015 and $0.4 million as of December 31, 2014, all of which is classified as a long-term liability in the accompanying unaudited condensed consolidated balance sheets. 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.
	Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three months ended March 31, 2015 and 2014 (in thousands):
		Three Months Ended March 31,
		2015		2014
	Producing overhead and supervision charges	$	733	$	375
	Drilling and completion supervision charges	38		9
	Saltwater disposal fees	244		415
	Total expenses incurred	$	1,015	$	799
	Receivables from New Dominion represent amounts due primarily for sale of our oil, natural gas and NGL production. Payables due to New Dominion represent amounts owed primarily for production costs associated with production of our oil, natural gas and NGL volumes. At March 31, 2015 and December 31, 2014, the Partnership had related party receivables, net from New Dominion of $4.4 million and $3.4 million, respectively.
	New Source Energy GP, LLC. 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, 2015 and 2014, the amount paid to our general partner for such reimbursements was approximately $0.03 million and $0.3 million, respectively, and was included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations. At March 31, 2015 and December 31, 2014, $0.2 million and $2.3 million, respectively, were due to our general partner for reimbursement and included in accounts payable - related party in the accompanying unaudited condensed consolidated balance sheets.
	Transactions with Chief Financial Officer. The Partnership engaged Finley & Cook, PLLC ("Finley & Cook") to provide various accounting services on our behalf during the three months ended March 31, 2015 and 2014. Richard Finley, the Chief Financial Officer of our general partner, was an equity member of Finley & Cook until October 2014, holding a 31.5% ownership interest. As Mr. Finley has subsequently continued in an advisory capacity with Finley & Cook, accounting services received from Finley & Cook during the first quarter of 2015 are included as related party transactions. The Partnership paid Finley & Cook approximately $0.1 million in fees for each of the three months ended March 31, 2015 and 2014.
	Acquisitions. In June 2014, we exercised our option to acquire MCCS, which was owned by Mr. Kos and Mr. Tourian. See Note 2 "Acquisitions" for discussion of this acquisition and Note 12 "Commitments and Contingencies" for discussion of the MCCS Contingent Consideration. As part of the acquisition of MCCS, we assumed a payable to an entity owned by Mr. Kos and Mr. Tourian. The resulting $0.7 million related party payable was paid as of December 31, 2014.
	On January 9, 2015, MCES acquired two separate parcels of land, one located in Canadian County, Oklahoma and one located in Ector County, Texas, from an entity owned 50% by Mr. Kos and 50% by Mr. Tourian for approximately $0.9 million. Additionally, on February 24, 2015, MCES acquired land located in Karnes County, Texas from an entity owned 67% by Mr. Kos and 33% by Mr. Tourian for approximately $0.5 million. The purchase price for each transaction was determined based on independent third-party appraisals for each property. In each transaction, a promissory note for the entire purchase price was issued by MCES to Mr. Kos and Mr. Tourian and is payable on December 31, 2015.
	Since the Chairman and Chief Executive Officer of our general partner, Kristian B. Kos, through his control of our general partner, is deemed to control the Partnership and also controls the entities that sold MCES land, the portion of the land acquired from Mr. Kos was recorded at his carrying value, which totaled $0.6 million for the three parcels of land at the time of acquisition. The difference between Mr. Kos' carrying value and the purchase price was reflected in equity.
	See Note 3 "Debt" for additional discussion on these notes payable.

Property_Plant_and_Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment
	Oil and Natural Gas Properties. We use the full cost method to account for our oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties, internal costs directly related to our acquisition and exploration and development activities.
	Under the full cost method of accounting, the net book value of oil and natural gas, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved oil and natural gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas, plus the cost of properties not subject to amortization. In calculating future net revenues, prices and costs used are based on the most recent 12-month average. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. The net book value, less related deferred tax liabilities, is compared to the ceiling limitation on a quarterly and annual basis. Any excess of the net book value, less related deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling limitation in the subsequent period.
	Based on the 12-month average prices of oil, natural gas and NGLs as of March, 31, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015. Continued low levels or further declines in oil, natural gas and NGL prices subsequent to March 31, 2015 are expected to result in additional ceiling test write downs in the second quarter of 2015 and in subsequent periods. The amount of any future impairment is difficult to predict, and will primarily depend on oil, natural gas and NGL prices during these periods.
	Property and equipment, net. Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):
		31-Mar-15			31-Dec-14
	Vehicles and transportation equipment	$	16,165		$	15,891
	Machinery and equipment	47,717			44,441
	Office furniture and equipment	1,518			1,069
	Iron	13,390			12,258
	Total	78,790			73,659
	Less: accumulated depreciation	(7,247		)	(4,773		)
		71,543			68,886
	Land	1,201			—
	Property and equipment, net	$	72,744		$	68,886

Asset_Retirement_Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Asset Retirement Obligations
	A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2014 to March 31, 2015 is as follows (in thousands):
	Asset retirement obligation at January 1, 2015	$	3,681
	Liability incurred upon acquiring and drilling wells	—
	Accretion	74
	Asset retirement obligation at March 31, 2015	3,755
	Less current portion	116
	Asset retirement obligations, net of current	$	3,639

Commitments_and_Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2015
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 9 "Related Party Transactions." 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.
	New Dominion serves as the operator for all of our properties. The successful operation of our exploration and production business depends on continued utilization of New Dominion’s oil, natural gas, and NGL infrastructure and technical staff as the operator of our properties. Failure of New Dominion to perform its obligations could have a material adverse effect on our operations and our financial results.
	Contingent Consideration
	MCE. The former owners of MCE were entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE, excluding EFS, RPS and MCCS, for the trailing nine month period ending March 31, 2015, less certain adjustments and subject to a $120.0 million cap. The contingent consideration was valued at $6.3 million at the acquisition date and was included in the consideration for the MCE Acquisition. Based on actual results for MCE for the nine month period ending March 31, 2015, the MCE Contingent Consideration was deemed to have no value at March 31, 2015.
	MCCS. The former owners of MCCS were entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $4.5 million cap. The contingent consideration was valued at $4.1 million at the acquisition date and was included in the consideration for the MCCS Acquisition. Based on actual results for MCCS for the nine month period ending March 31, 2015, the MCCS Contingent Consideration was deemed to have no value at March 31, 2015.
	EFS/RPS. The former owners of EFS and RPS are entitled to receive additional consideration in the form of cash and common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments. The terms of the contribution agreement provide that the additional consideration is to be paid approximately 50% in cash and approximately 50% in common units, consistent with the initial consideration for the Services Acquisition. However, the former owners can elect to receive a larger portion of the payout in common units. The EFS/RPS Contingent Consideration was valued at $22.0 million as of the acquisition date and was included in the consideration for the Services Acquisition. The fair value of the EFS/RPS Contingent Consideration was $23.3 million as of December 31, 2014.
	In March 2015, we entered into an agreement with the former owners that allows for the payment of the cash portion of the EFS/RPS Contingent Consideration to be extended to May 2016. Beginning in June 2015, interest payments are due monthly with principal and any unpaid interest due May 1, 2016. This agreement also restricts equity compensation and bonus payments to certain officers of the Partnership as well as the Partnership's ability to acquire another entity until this note has been paid. As a result, this portion of the EFS/RPS Contingent Consideration has been reflected as a long-term liability in the accompanying consolidated balance sheet as of March 31, 2015. Additionally, a receivable of approximately $1.0 million due from the former owners has been offset against the cash portion of the contingent consideration obligation.
	Legal Matters
	On January 12, 2015, David J. Chernicky, the beneficial owner of approximately 30.6% of our general partner, approximately 15.6% of our common units and all of our subordinated units, and his affiliated entities, Scintilla, LLC, New Source Energy Corporation and New Dominion, LLC (collectively, “plaintiffs”) filed a lawsuit against the Partnership, our general partner and certain current officers of our general partner, including Chairman and Chief Executive Officer, Kristian Kos, and Chief Financial Officer, Richard Finley, and certain of their affiliated entities (collectively, “defendants”) in the District Court of Tulsa County, Oklahoma. The plaintiffs allege various claims against the defendants, including that plaintiffs did not receive fair value for various oil and natural gas working interests acquired from them by the Partnership. The plaintiffs also allege that the Partnership has been unjustly enriched and that the properties acquired from them by the Partnership pursuant to the transactions in question should be held in a constructive trust in favor of the plaintiffs. Additionally, the plaintiffs claim that the defendants have conspired to commit constructive fraud, breach of fiduciary duty, negligence and gross negligence against the plaintiffs. Additionally, the plaintiffs allege that the defendants have intentionally interfered with the defendants' current business arrangements with certain working interest owners in the properties the plaintiffs operate as well as future business opportunities. The plaintiffs also claim that the Partnership is wrongfully refusing to remove the restrictive legends on common units issued by the Partnership to the plaintiffs in private transactions in exchange for the oil and natural gas working interests described above.
	On February 23, 2015, the defendants filed several motions to dismiss the claims raised in the plaintiffs’ petition, including motions by the Partnership and our general partner that (i) the defendants' claims fail to state a claim; (ii) the defendants' claims are time barred by statues of limitations; and (iii) Tulsa County is an improper venue. A hearing on the motions to dismiss is currently scheduled to be held on May 26, 2015. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action.
	In addition to the proceeding described above, on January 29, 2015, the Partnership received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by the Partnership to NSEC. The total amount of the purported claims totaled approximately $1.9 million. In 2015, New Dominion has withheld all revenue from the Partnership's sold oil and natural gas production in satisfaction of these claims as well as other amounts that the Partnership has disputed. As with the proceeding described above, the Partnership intends to pursue this matter vigorously and believes the claims are without any substantial merit. The Partnership has not established any reserves relating to this action.
	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 ("Scissortail"). The plaintiffs assert that royalties to the class should be paid based upon the price received by Scissortail for the natural gas and its components at the tailgate of the plant, rather than the price paid by Scissortail at the wellhead where the natural gas is purchased. The plaintiffs assert a variety of breach of contract and tort claims. A hearing on the matter was held in August 2014 at which Scissortail’s motion to dismiss was granted with prejudice and New Dominion’s motion to dismiss was granted in part. The plaintiffs have appealed the court's granting of the dismissal. In January, the appeal was assigned to the Court of Civil Appeals in Tulsa, Oklahoma. A class certification hearing has also been set for November 2015.
	Any liability on the part of New Dominion, as contract operator, would be allocated to the working interest owners to pay their proportionate share of such liability. While the outcome and impact on the Partnership of this proceeding cannot be predicted with certainty, management believes a loss of up to $250,000 may be reasonably possible. Due to the uncertainty, no reserve has been established for this matter.
	The Partnership may be involved in other various routine legal proceedings incidental to its business from time to time. While the results of litigation and claims cannot be predicted with certainty, the Partnership believes the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, the Partnership believes the probable final outcome of such matters will not have a material adverse effect on the Partnership's consolidated financial position, results of operations, cash flow or liquidity.

Business_Segment_Information

Business Segment Information	3 Months Ended
	Mar. 31, 2015
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 and its general and administrative expenses include certain costs of our corporate administrative functions and changes in the fair value of contingent consideration obligations related to all acquisitions. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, as well as well testing and flowback services. Our oilfield services segment is the aggregation of multiple operating segments that meet the criteria for aggregation due to the economic similarities as well as the similarities in the nature of the services provided, customers served and industry regulations monitored.
	Management evaluates the performance of the Partnership’s business segments based on the excess of revenue over direct operating expenses or segment margin. Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands):
			Exploration and Production			Oilfield Services			Total
	Three Months Ended March 31, 2015
	Revenues		$	6,567		$	31,550		$	38,117
	Direct operating expenses		4,366			23,059			27,425
	Segment margin		$	2,201		$	8,491		$	10,692
	Depreciation, depletion, amortization and accretion		4,794			7,627			12,421
	Impairment of oil and natural gas properties		43,119			—			43,119
	General and administrative expenses		4,569			7,665			12,234
	Loss from operations		$	(50,281	)	$	(6,801	)	$	(57,082	)
	Capital expenditures (1)		$	1,014		$	6,103		$	7,117
	At March 31, 2015
	Total assets (2)		$	149,200		$	166,333		$	315,533
	Three Months Ended March 31, 2014
	Revenues		$	18,851		$	8,576		$	27,427
	Direct operating expenses		5,382			4,566			9,948
	Segment margin		$	13,469		$	4,010		$	17,479
	Depreciation, depletion, amortization and accretion		5,887			3,460			9,347
	General and administrative expenses		3,843			1,717			5,560
	Income (loss) from operations		$	3,739		$	(1,167	)	$	2,572
	Capital expenditures (1)		$	10,072		$	3,143		$	13,215
	At December 31, 2014
	Total assets		$	199,178		$	176,368		$	375,546
	__________
	-1	On an accrual basis and exclusive of acquisitions.
	-2	Exploration and Production includes impairment of oil and natural gas properties of $43.1 million as discussed in Note 10 "Property, Plant and Equipment."
			Exploration and Production		Oilfield Services (1)	Total

Subsequent_Events

Subsequent Events	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events
	Ownership of Our General Partner. On April 27, 2015, the Partnership entered into a purchase agreement among the Partnership for certain limited purposes, Deylau and 2100 Energy LLC (“2100 Energy”). Prior to the consummation of the transactions contemplated by the Purchase Agreement, Deylau, owned 69.4% of the limited liability company interest in our general partner.
	Pursuant to the purchase agreement, (i) Deylau made an initial transfer of 26.5% of its limited liability company interest in our general partner (which constitutes an 18.4% limited liability company interest in our general partner) to 2100 Energy (the “Initial Transfer”), and (ii) following the Initial Transfer and the satisfaction of various conditions (including 2100 Energy causing one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, sell $150 million of oil and natural gas assets to a subsidiary of the Partnership), (A) Deylau will transfer its remaining limited liability company interest in our general partner (which constitutes a 51.0% limited liability company interest in our general partner) to 2100 Energy and (B) the Partnership will transfer all of its limited liability company interest in MCE GP, the general partner of MCLP, to an entity owned, directly or indirectly, by Deylau and Signature Investments LLC, which is wholly-owned by Mr. Tourian. Following such transactions, the Partnership will still own all of the equity interests in MCLP except for the general partner interest and the Class B units.
	Exchange Agreement. On April 27, 2015, the Partnership entered into an exchange agreement with our general partner (the “Exchange Agreement”). Pursuant to the Exchange Agreement, our general partner eliminated the economic portion of its general partner interest in the Partnership and canceled all of its general partner units in exchange for the issuance by the Partnership of an equivalent amount of 155,102 common units, which were subsequently distributed to the members of our general partner pro rata in accordance with their ownership interest. The general partner interest ceased to be an economic interest in the Partnership; however, our general partner continues to be the general partner of the Partnership.
	Amendments to Credit Agreement. On April 27, 2015, we entered into a Seventh Amendment (the "Seventh Amendment")to our credit agreement governing our credit facility, which, among other things, (i) amends the Change in Control definition to provide for 2100 Energy’s acquisition of Deylau’s limited liability company interest in our general partner, (ii) increased certain of the collateral requirements, (iii) granted the Partnership the ability to make certain cash distributions to the holders of the Partnership's common units that are not otherwise permitted by the credit agreement and (iv) permits us to dispose all of our limited liability company interest in MCE GP upon the satisfaction of various conditions (including 2100 Energy causing one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, transfer $150 million of oil and natural gas assets to a subsidiary of us) as described above. On May 1, 2015, we entered into an Eighth Amendment (the "Eighth Amendment") to the credit agreement governing our credit facility. The Eighth Amendment (i) permits the Partnership to make cash distributions up to $6.0 million per year to holders of our Series A Preferred Units, (ii) amends the terms of a consent letter dated April 8, 2015 ("Consent Letter"), by and among the Partnership, Bank of Montreal and the other lenders party to the credit agreement, to postpone the redetermination of the borrowing base under our credit facility until May 8, 2015, (iii) makes null and void the waiver contained in the Seventh Amendment to the credit agreement permitting the Partnership to make certain cash distributions to the holders of the Partnership's common units that are not otherwise permitted by the credit agreement and (iv) imposes certain hedging requirements for our oil and natural gas assets if the Partnership unwinds any current hedges prior to the October 2015 redetermination date. As a result of the Eighth Amendment, distributions to common unitholders are not permitted unless the amount outstanding is 90% or less of the current borrowing base.
	Preferred Units Offering.  On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. The Series A Preferred Units are cumulative convertible preferred units that are entitled to receive quarterly cash distributions at the rate of 11.00% per annum. The Series A Preferred Units are convertible into our common units on any January 1, April 1, July 1 or October 1 by the holder and we may elect to convert the Series A Preferred Units into our common units on or after July 15, 2018 in certain circumstances. The initial conversion rate for the Series A Preferred Units is 3.7821 common units per Series A Preferred Unit and they are mandatorily redeemable by the holder on or after July 15, 2022. We will redeem all of the Series A Preferred on July 15, 2022 at a redemption price equal to the liquidation preference of $25.00 plus an amount equal to accumulated but unpaid distributions thereon. If we do not redeem the Series A Preferred Units on July 15, 2022, then the per annum distribution rate will increase by an additional 2.00% per month until such redemption, up to a maximum rate per annum of 20.00%.
	We received net proceeds of approximately $40.4 million from this offering after deducting underwriting discounts of $2.6 million and estimated offering costs of $1.0 million.  We used all of the net proceeds from the offering to repay a portion of the indebtedness outstanding under our credit facility. The Partnership has granted the underwriters a 30-day option to purchase up to 264,000 additional Series A Preferred Units.
	Distributions. On May 8, 2015, the Partnership declared quarterly distributions of $0.20 per unit to unitholders of record, including holders of common units for the three months ended March 31, 2015. The following distributions will be paid on May 15, 2015 to holders of record as of the close of business on May 11, 2015 (in thousands):
		Common Units		Subordinated Units		General Partner Units		Total
	Distributions	$	3,312	$	—	$	—	$	3,312

Basis_of_Presentation_Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Interim Financial Statements	Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2014 have been derived from the audited financial statements contained in the Partnership’s 2014 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 2014 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 accompanying 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 2014 Form 10-K.
Reclassifications	Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Partnership's previously reported results of operations.
Use of Estimates	Use of Estimates. The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed and asset retirement obligations. Actual results could differ from those estimates.
Recently Issued Accounting Standard	Recently Issued Accounting Standard. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, ("ASU 2014-09"), which revises the guidance on revenue recognition by providing a single, principles-based method for companies to use to account for revenue arising from contracts with customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard permits the use of either the retrospective or cumulative effect transition method. ASU 2014-09 is effective for fiscal years beginning after December 15, 2016. Early application is not permitted. We are in the process of assessing which transition method we will apply and the potential impact of ASU 2014-09 on the Partnership's financial statements. In April 2015, the FASB voted to propose to defer the effective date by one year.
	In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We are currently evaluating the effect, if any, the guidance will have on our related disclosures.
	In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.
	In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction from the carrying amount of the debt. The new standard does not change the recognition and measurement of debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect the guidance will have on our consolidated financial statements and related disclosures.
Oil and Natural Gas Properties	Oil and Natural Gas Properties. We use the full cost method to account for our oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties, internal costs directly related to our acquisition and exploration and development activities.
	Under the full cost method of accounting, the net book value of oil and natural gas, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved oil and natural gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas, plus the cost of properties not subject to amortization. In calculating future net revenues, prices and costs used are based on the most recent 12-month average. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. The net book value, less related deferred tax liabilities, is compared to the ceiling limitation on a quarterly and annual basis. Any excess of the net book value, less related deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling limitation in the subsequent period.

Acquisitions_Tables

Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Cash	$	109
	Accounts receivable	524
	Inventory	2,035
	Other current assets	14
	Property and equipment	107
	Intangible asset (1)	1,700
	Goodwill (2)	3,382
	Other assets	28
	Total assets acquired	7,899
	Accounts payable and accrued liabilities	(1,431		)
	Long-term debt	(791		)
	Total liabilities assumed	(2,222		)
	Net assets acquired	$	5,677
	__________
	-1	Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.
	-2	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS' business.
	Total consideration for the Services Acquisition is as follows (in thousands):
	Consideration:
	Cash	$	57,348
	Fair value of common units granted (1)	33,106
	Common units granted for the benefit of EFS and RPS employees (2)	724
	Contingent consideration (3)	21,984
	Total fair value of consideration	$	113,162
	__________
	-1	The fair value of the unit consideration was based upon 1,411,777 common units valued at $23.45 per unit (closing price on the date of the acquisition).
	-2	The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 7 "Equity" for additional discussion of phantom units.
	-3	The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 12 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.
	The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Cash	$	1,668
	Accounts receivable	22,674
	Other current assets	620
	Property and equipment	43,853
	Intangible assets (1)	68,700
	Goodwill (2)	14,224
	Total assets acquired	151,739
	Accounts payable and accrued liabilities	(5,937		)
	Factoring payable	(15,840		)
	Long-term debt	(16,800		)
	Total liabilities assumed	(38,577		)
	Net assets acquired	$	113,162
	__________
	-1	Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years. Non-compete agreements were valued based on an income approach and are amortized over the agreement period.
	-2	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS and RPS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships. Goodwill has been allocated to the oilfield services segment.
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition, net of purchase price adjustments, is as follows (in thousands):
	Consideration:
	Cash	$	5,503
	Fair value of common units granted (1)	11,621
	Contingent consideration (2)	—
	Total fair value of consideration	$	17,124
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	17,306
	Asset retirement obligations	(182		)
	Total net assets	$	17,124
	__________
	-1	The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition).
	-2	The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU.
	Total consideration for the MCCS Acquisition is as follows (in thousands):
	Consideration:
	Fair value of common units granted (1)	$	789
	Contingent consideration (2)	4,057
	Noncontrolling interest (3)	831
Total fair value of consideration	$	5,677
__________
-1	The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition).
-2	The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 12 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
-3	As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.
Business Acquisition, Pro Forma Information
		Three Months Ended March 31, 2014
		(in thousands, except per unit amounts)
	Revenue	$	60,285
	Net income attributable to New Source Energy Partners L.P.	$	2,107
	Net income per common unit:
	Basic	$	0.13
	Diluted	$	0.13
Summary of Operating Results
			Three Months Ended March 31, 2014
		(in thousands)
	Revenue		$	1,883
	Excess of revenue over direct operating expenses		$	1,119

Debt_Tables

Debt (Tables)	3 Months Ended
	Mar. 31, 2015
Debt Disclosure [Abstract]
Schedule of Debt	The Partnership's debt consists of the following (in thousands):
		31-Mar-15		31-Dec-14
	Credit facility	$	84,000	$	83,000
	Notes payable	19,652		20,424
	Line of credit	3,429		3,619
	Total debt	107,081		107,043
	Less: current maturities of long-term debt	12,277		11,825
	Long-term debt	$	94,804	$	95,218

Derivative_Contracts_Tables

Derivative Contracts (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative [Line Items]
Schedule of Derivative Instruments	At March 31, 2015, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:
	Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.
	Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.
	Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the market price and the fixed price.
	Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table summarizes our derivative contracts on a gross basis and the effects of netting assets and liabilities for which the right of offset exists (in thousands):
	31-Mar-15		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset				Net Amounts Presented
	Assets:
	Commodity derivatives - current assets		$	7,292			$	—			$	7,292
	Commodity derivatives - long-term assets		1,659				—				1,659
	Total		$	8,951			$	—			$	8,951
	Liabilities:
	Commodity derivatives - current liabilities		$	—			$	—			$	—
	Commodity derivatives - long-term liabilities		—				—				—
	Total		$	—			$	—			$	—
	31-Dec-14		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset				Net Amounts Presented
	Assets:
	Commodity derivatives - current assets		$	8,309			$	(61	)		$	8,248
	Commodity derivatives - long-term assets		1,818				—				1,818
	Total		$	10,127			$	(61	)		$	10,066
	Liabilities:
	Commodity derivatives - current liabilities		$	61			$	(61	)		$	—
	Commodity derivatives - long-term liabilities		—				—				—
	Total		$	61			$	(61	)		$	—
	The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis (in thousands):
	31-Mar-15		Fair Value Measurements
	Description		Active Markets for Identical Assets (Level 1)				Observable Inputs (Level 2)				Unobservable Inputs (Level 3)				Total Carrying Value
	Oil and natural gas collars		$	—			$	2,436			$	—			$	2,436
	Oil, natural gas and NGL put options		—				1,035				—				1,035
	Oil, natural gas and NGL fixed price swaps		—				5,480				—				5,480
	Total		$	—			$	8,951			$	—			$	8,951
	31-Dec-14		Fair Value Measurements
	Description		Active Markets for Identical Assets (Level 1)				Observable Inputs (Level 2)				Unobservable Inputs (Level 3)				Total Carrying Value
	Oil and natural gas collars		$	—			$	2,411			$	—			$	2,411
	Oil, natural gas and NGL put options		—				1,405				—				1,405
	Oil, natural gas and NGL fixed price swaps		—				6,250				—				6,250
	Contingent consideration		—				—				(23,330		)		(23,330		)
	Total		$	—			$	10,066			$	(23,330	)		$	(13,264	)
	The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2014 (in thousands):
			Three Months Ended March 31, 2014
	Beginning balance		$	(2,517	)
	Loss on derivative contracts		(2,432		)
	Cash paid upon settlement		2,106
	Ending balance (1)		$	(2,843	)
	Unrealized losses included in earnings relating to derivatives held at period end		$	(702	)
Derivative Instruments, Gain (Loss)	The following table presents gain (loss) on our derivative contracts as included in the accompanying unaudited statements of operations for the three months ended March 31, 2015 and 2014 (in thousands):
			Three Months Ended March 31,
			2015				2014
	Total gain (loss) on derivative contracts, net (1)		$	1,224			$	(3,132	)
	__________
	-1	Included in gain (loss) on derivative contracts for the three months ended March 31, 2015 and 2014 are net cash receipts (payments) upon contract settlement of $2.3 million and $(2.4) million, respectively.
Oil Collar [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The following tables present our derivative instruments outstanding as of March 31, 2015:
	Oil collars		Volumes			Floor Price				Ceiling Price
			(Bbls)
	2015		30,072			$	80			$	93.25
Oil Collars - Three Way [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Oil collars - three way		Volumes			Sold Put				Purchased Put				Ceiling Price
			(Bbls)
	2015		27,500			$	77.5			$	92.5			$	102.6
Oil Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Oil fixed price swaps		Volumes (Bbls)			Weighted Average Fixed Price
	2015		30,080			$	88.9
	2016		36,658			$	86
Natural Gas Collars [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Natural gas collars		Volumes			Floor Price				Ceiling Price
			(MMBtu)
	2015		976,356			$	4			$	4.32
Natural Gas Options [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Natural gas put options		Volumes			Floor Price
			(MMBtu)
	2015		620,040			$	3.5
	2016		930,468			$	3.5
Natural Gas Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Natural gas fixed price swaps		Volumes			Weighted Average Fixed Price
			(MMBtu)
	2015		582,451			$	4.25
	2016		629,301			$	4.37
Natural Gas Liquid Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	NGL fixed price swaps		Volumes			Weighted Average Fixed Price
			(Bbls)
	2015		62,213			$	75.18

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table summarizes our derivative contracts on a gross basis and the effects of netting assets and liabilities for which the right of offset exists (in thousands):
	31-Mar-15	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset			Net Amounts Presented
	Assets:
	Commodity derivatives - current assets	$	7,292		$	—		$	7,292
	Commodity derivatives - long-term assets	1,659			—			1,659
	Total	$	8,951		$	—		$	8,951
	Liabilities:
	Commodity derivatives - current liabilities	$	—		$	—		$	—
	Commodity derivatives - long-term liabilities	—			—			—
	Total	$	—		$	—		$	—
	31-Dec-14	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset			Net Amounts Presented
	Assets:
	Commodity derivatives - current assets	$	8,309		$	(61	)	$	8,248
	Commodity derivatives - long-term assets	1,818			—			1,818
	Total	$	10,127		$	(61	)	$	10,066
	Liabilities:
	Commodity derivatives - current liabilities	$	61		$	(61	)	$	—
	Commodity derivatives - long-term liabilities	—			—			—
	Total	$	61		$	(61	)	$	—
	The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis (in thousands):
	31-Mar-15	Fair Value Measurements
	Description	Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
	Oil and natural gas collars	$	—		$	2,436		$	—		$	2,436
	Oil, natural gas and NGL put options	—			1,035			—			1,035
	Oil, natural gas and NGL fixed price swaps	—			5,480			—			5,480
	Total	$	—		$	8,951		$	—		$	8,951
	31-Dec-14	Fair Value Measurements
	Description	Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
	Oil and natural gas collars	$	—		$	2,411		$	—		$	2,411
	Oil, natural gas and NGL put options	—			1,405			—			1,405
	Oil, natural gas and NGL fixed price swaps	—			6,250			—			6,250
	Contingent consideration	—			—			(23,330		)	(23,330		)
	Total	$	—		$	10,066		$	(23,330	)	$	(13,264	)
	The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2014 (in thousands):
		Three Months Ended March 31, 2014
	Beginning balance	$	(2,517	)
	Loss on derivative contracts	(2,432		)
	Cash paid upon settlement	2,106
	Ending balance (1)	$	(2,843	)
	Unrealized losses included in earnings relating to derivatives held at period end	$	(702	)

Equity_Tables

Equity (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Schedule of Distributions Made to Units	Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the three months ended March 31, 2015 and 2014, as shown in the following table (in thousands):
	Distributions		Payable Date		Distribution per Unit				Common Units				Subordinated Units				General Partner Units		Total
	2015
	First Quarter		15-May-15		$	0.2			$	3,312			$	—			$	—	$	3,312
	2014
	First Quarter		15-May-14		$	0.58			$	7,852			$	1,279			$	90	$	9,221
	The following distributions will be paid on May 15, 2015 to holders of record as of the close of business on May 11, 2015 (in thousands):
			Common Units				Subordinated Units				General Partner Units				Total
	Distributions		$	3,312			$	—			$	—			$	3,312
Schedule of Target Distributions to Unitholders	The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels, as adjusted based on the MCCS Acquisition.
						Marginal Percentage Interest in
						Distributions
		Total Quarterly Distributions per MCE Unit				MCE Class A Unitholders (the Partnership)		MCE Class B Unitholders
	Minimum Quarterly Distribution	$16,116				100%		—%
	First Target Distribution	$18,533	to	$20,144		85%		15%
	Second Target Distribution	$20,145	to	$24,173		75%		25%
	Third Target Distribution and Thereafter	$24,174	and above			50%		50%

Earnings_per_Unit_Tables

Earnings per Unit (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	Basic and diluted earnings per unit for the three months ended March 31, 2015 and 2014 were computed as follows (in thousands, except per unit amounts):
		Three Months Ended
		March 31, 2015
		Common Units			Subordinated Units			General Partner
	Net loss	$	(49,574	)	$	(7,128	)	$	(470	)
	Weighted average units outstanding	16,346			2,205			155
	Basic and diluted loss per unit	$	(3.03	)	$	(3.23	)	$	(3.03	)
		Three Months Ended
		March 31, 2014
		Common Units			Subordinated Units			General Partner
	Net loss	$	(1,241	)	$	(271	)	$	(19	)
	Weighted average units outstanding	9,920			2,205			155
	Basic and diluted loss per unit	$	(0.12	)	$	(0.12	)	$	(0.12	)

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three months ended March 31, 2015 and 2014 (in thousands):
		Three Months Ended March 31,
		2015		2014
	Producing overhead and supervision charges	$	733	$	375
	Drilling and completion supervision charges	38		9
	Saltwater disposal fees	244		415
	Total expenses incurred	$	1,015	$	799

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):
		31-Mar-15			31-Dec-14
	Vehicles and transportation equipment	$	16,165		$	15,891
	Machinery and equipment	47,717			44,441
	Office furniture and equipment	1,518			1,069
	Iron	13,390			12,258
	Total	78,790			73,659
	Less: accumulated depreciation	(7,247		)	(4,773		)
		71,543			68,886
	Land	1,201			—
	Property and equipment, net	$	72,744		$	68,886

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2014 to March 31, 2015 is as follows (in thousands):
	Asset retirement obligation at January 1, 2015	$	3,681
	Liability incurred upon acquiring and drilling wells	—
	Accretion	74
	Asset retirement obligation at March 31, 2015	3,755
	Less current portion	116
	Asset retirement obligations, net of current	$	3,639

Business_Segment_Information_T

Business Segment Information (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands):
			Exploration and Production			Oilfield Services			Total
	Three Months Ended March 31, 2015
	Revenues		$	6,567		$	31,550		$	38,117
	Direct operating expenses		4,366			23,059			27,425
	Segment margin		$	2,201		$	8,491		$	10,692
	Depreciation, depletion, amortization and accretion		4,794			7,627			12,421
	Impairment of oil and natural gas properties		43,119			—			43,119
	General and administrative expenses		4,569			7,665			12,234
	Loss from operations		$	(50,281	)	$	(6,801	)	$	(57,082	)
	Capital expenditures (1)		$	1,014		$	6,103		$	7,117
	At March 31, 2015
	Total assets (2)		$	149,200		$	166,333		$	315,533
	Three Months Ended March 31, 2014
	Revenues		$	18,851		$	8,576		$	27,427
	Direct operating expenses		5,382			4,566			9,948
	Segment margin		$	13,469		$	4,010		$	17,479
	Depreciation, depletion, amortization and accretion		5,887			3,460			9,347
	General and administrative expenses		3,843			1,717			5,560
	Income (loss) from operations		$	3,739		$	(1,167	)	$	2,572
	Capital expenditures (1)		$	10,072		$	3,143		$	13,215
	At December 31, 2014
	Total assets		$	199,178		$	176,368		$	375,546
	__________
	-1	On an accrual basis and exclusive of acquisitions.
	-2	Exploration and Production includes impairment of oil and natural gas properties of $43.1 million as discussed in Note 10 "Property, Plant and Equipment."

Subsequent_Events_Tables

Subsequent Events (Tables)	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Schedule of Distributions Made to Units	Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the three months ended March 31, 2015 and 2014, as shown in the following table (in thousands):
	Distributions	Payable Date		Distribution per Unit				Common Units				Subordinated Units				General Partner Units		Total
	2015
	First Quarter	15-May-15		$	0.2			$	3,312			$	—			$	—	$	3,312
	2014
	First Quarter	15-May-14		$	0.58			$	7,852			$	1,279			$	90	$	9,221
	The following distributions will be paid on May 15, 2015 to holders of record as of the close of business on May 11, 2015 (in thousands):
		Common Units				Subordinated Units				General Partner Units				Total
	Distributions	$	3,312			$	—			$	—			$	3,312

Acquisitions_Details

Acquisitions (Details) (USD $)	12 Months Ended	0 Months Ended				3 Months Ended
	Dec. 31, 2014	Jan. 31, 2014		Jun. 26, 2014		Mar. 31, 2015
		producing_well
Common Units [Member]
Business Acquisition [Line Items]
Issuance of common units in acquisitions (in units)	1,964,957
Southern Dome [Member]
Business Acquisition [Line Items]
Number of wells in which Company has acquired working interests	23
CEU Paradigm [Member]
Business Acquisition [Line Items]
Number of wells in which Company has acquired working interests		23
Total fair value of consideration		$17,124,000
Issuance of common units in acquisitions (in units)		488,667
Value of units issued in acquisition (in usd per unit)		$23.78
Contingent consideration		0	[1]
MCCS [Member]
Business Acquisition [Line Items]
Total fair value of consideration				5,677,000
Issuance of common units in acquisitions (in units)				33,646
Value of units issued in acquisition (in usd per unit)				$23.45
Equity interest percentage acquired in acquisition				100.00%
Contingent consideration				4,057,000	[2]	4,100,000
Gain on acquisition of business				2,300,000
Intangible asset				1,700,000	[3]
MCCS [Member] | Chief Executive Officer [Member]
Business Acquisition [Line Items]
Ownership percentage of acquired entity				50.00%
Equity method carrying basis in acquisition				100,000
MCCS [Member] | Customer Relationships [Member]
Business Acquisition [Line Items]
Useful life of finite-lived intangible asset						7 years
MCCS [Member] | Maximum [Member]
Business Acquisition [Line Items]
Contingent consideration				4,500,000		4,500,000
EFS [Member]
Business Acquisition [Line Items]
Equity interest percentage acquired in acquisition				100.00%
EFS [Member] | EFS Employees [Member]
Business Acquisition [Line Items]
Issuance of common units in acquisitions (in units)				30,867
Value of units issued in acquisition (in usd per unit)				$23.45
RPS [Member]
Business Acquisition [Line Items]
Equity interest percentage acquired in acquisition				100.00%
EFS and RPS [Member]
Business Acquisition [Line Items]
Total fair value of consideration				113,162,000
Issuance of common units in acquisitions (in units)				1,411,777
Value of units issued in acquisition (in usd per unit)				$23.45
Contingent consideration				21,984,000	[4]	23,300,000
Intangible asset				68,700,000	[5]
EFS and RPS [Member] | Common Units [Member] | Phantom Units [Member]
Business Acquisition [Line Items]
Phantom units granted (in units)				432,038
EFS and RPS [Member] | Service Requirement Units [Member] | Common Units [Member] | Phantom Units [Member]
Business Acquisition [Line Items]
Phantom units granted (in units)				401,171
EFS and RPS [Member] | Customer Relationships [Member]
Business Acquisition [Line Items]
Useful life of finite-lived intangible asset						7 years
Intangible asset				64,200,000
EFS and RPS [Member] | Noncompete Agreements [Member]
Business Acquisition [Line Items]
Intangible asset				$4,500,000
[1]	The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU.
[2]	The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 12 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
[3]	Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years
[4]	The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 12 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.
[5]	Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years. Non-compete agreements were valued based on an income approach and are amortized over the agreement period.

Acquisitions_Purchase_Price_Al

Acquisitions - Purchase Price Allocation of CEU Acquisition (Details) (CEU Paradigm [Member], USD $)	0 Months Ended
	Jan. 31, 2014
CEU Paradigm [Member]
Business Acquisition [Line Items]
Cash	$5,503,000
Fair value of common units granted	11,621,000	[1]
Contingent consideration	0	[2]
Total fair value of consideration	17,124,000
Property and equipment	17,306,000
Asset retirement obligations	-182,000
Total net assets	$17,124,000
[1]	The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition).
[2]	The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU.

Acquisitions_Purchase_Price_Al1

Acquisitions - Purchase Price Allocation for MCCS Acquisition (Details) (USD $)	0 Months Ended
	Jun. 26, 2014		Mar. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Noncontrolling interest			$17,420,000	$17,420,000
MCCS [Member]
Business Acquisition [Line Items]
Fair value of common units granted	789,000	[1]
Contingent consideration	4,057,000	[2]	4,100,000
Noncontrolling interest	831,000	[3]
Total fair value of consideration	$5,677,000
[1]	The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition).
[2]	The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 12 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
[3]	As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.

Acquisitions_Summary_of_Assets

Acquisitions - Summary of Assets Acquired and Liabilities Assumed in MCCS Acquisition (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Jun. 26, 2014
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Goodwill	$9,315	$9,315
MCCS [Member]
Business Acquisition [Line Items]
Cash			109
Accounts receivable			524
Inventory			2,035
Other current assets			14
Property and equipment			107
Intangible asset			1,700	[1]
Goodwill			3,382	[2]
Other assets			28
Total assets acquired			7,899
Accounts payable and accrued liabilities			-1,431
Long-term debt			-791
Total liabilities assumed			-2,222
Total net assets			$5,677
[1]	Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years
[2]	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS' business.

Acquisitions_Purchase_Price_Al2

Acquisitions - Purchase Price Allocation of EFS and RPS Acquisition (Details) (EFS and RPS [Member], USD $)	0 Months Ended
	Jun. 26, 2014		Mar. 31, 2015
Business Acquisition [Line Items]
Cash	$57,348,000
Fair value of common units granted	33,106,000	[1]
Contingent consideration	21,984,000	[2]	23,300,000
Total fair value of consideration	113,162,000
EFS and RPS Employees [Member]
Business Acquisition [Line Items]
Common units granted for the benefit of EFS and RPS employees	$724,000	[3]
[1]	The fair value of the unit consideration was based upon 1,411,777 common units valued at $23.45 per unit (closing price on the date of the acquisition).
[2]	The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 12 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.
[3]	The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 7 "Equity" for additional discussion of phantom units.

Acquisitions_Summary_of_Assets1

Acquisitions - Summary of Assets Acquired and Liabilities Assumed in EFS and RPS Acquisition (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014	Jun. 26, 2014
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Goodwill	$9,315	$9,315
EFS and RPS [Member]
Business Acquisition [Line Items]
Cash			1,668
Accounts receivable			22,674
Other current assets			620
Property and equipment			43,853
Intangible asset			68,700	[1]
Goodwill			14,224	[2]
Total assets acquired			151,739
Accounts payable and accrued liabilities			-5,937
Factoring payable			-15,840
Long-term debt			-16,800
Total liabilities assumed			-38,577
Total net assets			113,162
Customer Relationships [Member] | EFS and RPS [Member]
Business Acquisition [Line Items]
Intangible asset			64,200
Noncompete Agreements [Member] | EFS and RPS [Member]
Business Acquisition [Line Items]
Intangible asset			$4,500
[1]	Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years. Non-compete agreements were valued based on an income approach and are amortized over the agreement period.
[2]	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS and RPS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships. Goodwill has been allocated to the oilfield services segment.

Acquisitions_Pro_Forma_Results

Acquisitions - Pro Forma Results of Operations (Details) (2014 Material Acquisitions [Member], USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015
2014 Material Acquisitions [Member]
Business Acquisition [Line Items]
Revenue	$60,285
Net income attributable to New Source Energy Partners L.P.	$2,107
Net income per common unit:
Basic (in usd per unit)	$0.13
Diluted (in usd per unit)	$0.13

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, 2015	Mar. 31, 2014
Business Acquisition [Line Items]
Revenue	$38,117	$27,427
Excess of revenue over direct operating expenses	-57,082	2,572
2014 Material Acquisitions [Member]
Business Acquisition [Line Items]
Revenue	1,883
Excess of revenue over direct operating expenses	$1,119

Debt_Schedule_of_Debt_Details

Debt - Schedule of Debt (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Line of Credit Facility [Line Items]
Outstanding Credit	$84,000	$83,000
Notes payable	19,652	20,424
Total debt	107,081	107,043
Less: current maturities of long-term debt	12,277	11,825
Long-term debt	94,804	95,218
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Outstanding Credit	$3,429	$3,619

Debt_Senior_Secured_Revolving_

Debt - Senior Secured Revolving Credit Facility - Narrative (Details) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	8-May-15	Dec. 31, 2014	1-May-15	Apr. 30, 2015
Line of Credit Facility [Line Items]
Maximum borrowing base utilization permitted under credit facility	90.00%
Outstanding balance of line of credit	$84,000,000		$83,000,000
Commitment fee percentage	0.50%
Interest rates on debt instruments	3.51%		3.44%
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit current borrowing capacity	90,000,000
Outstanding balance of line of credit	3,429,000		3,619,000
Minimum [Member]
Line of Credit Facility [Line Items]
Required ratio of EBITDA to interest expense	2.5
Required current ratio	1
Maximum [Member]
Line of Credit Facility [Line Items]
Required ratio of total debt to EBITDA	3.5
Subsequent Event [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit current borrowing capacity				60,000,000	84,000,000
Repayment of credit facility		41,000,000
Outstanding balance of line of credit				$43,000,000
Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	0.50%
London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	1.00%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	3.25%
Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	1.50%
Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	2.25%

Debt_Notes_Payable_Narrative_D

Debt - Notes Payable - Narrative (Details) (USD $)	3 Months Ended	0 Months Ended
	Mar. 31, 2015	Feb. 24, 2015	Dec. 31, 2014	Oct. 01, 2015
Debt Instrument [Line Items]
Current portion of long-term debt	12,277,000		$11,825,000
Interest rates on debt instruments	3.51%		3.44%
Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Long-term debt	6,500,000
Current portion of long-term debt	3,200,000
Loans Payable [Member]
Debt Instrument [Line Items]
Term loans balance	11,700,000
Current balance	4,200,000
Initial deposit required for loans	500,000
Loans Payable [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	-2.30%
Interest rates on debt instruments	5.50%
Minimum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	1.50%
Minimum [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Durations of debt instruments	12 months
Stated rates on debt instruments	5.50%
Minimum [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Minimum balance required to be maintained on reserve bank account	300,000
Minimum [Member] | Loans Payable [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Stated rates on debt instruments	5.50%
Maximum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	2.25%
Maximum [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Durations of debt instruments	60 months
Stated rates on debt instruments	10.51%
EFS and RPS [Member] | Minimum [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Required fixed-charge ratio	1.25
Required working capital and cash balance	1,000,000
EFS and RPS [Member] | Minimum [Member] | Loans Payable [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Required working capital and cash balance				3,500,000
EFS and RPS [Member] | Maximum [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Required leverage ratio	1.5
Commercial Paper [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments		1.00%
MidCentral Energy Partners LP [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt		1,400,000
Chief Executive Officer [Member] | MidCentral Energy Partners LP [Member]
Debt Instrument [Line Items]
Ownership percentage		50.00%
President [Member] | MidCentral Energy Partners LP [Member]
Debt Instrument [Line Items]
Ownership percentage		50.00%

Debt_Line_of_Credit_Narrative_

Debt - Line of Credit - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Dec. 31, 2014	Feb. 28, 2014
Line of Credit Facility [Line Items]
Interest rates on debt instruments	3.51%	3.44%
Outstanding balance of line of credit	$84,000,000	$83,000,000
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit current borrowing capacity	90,000,000
Outstanding balance of line of credit	3,429,000	3,619,000
Revolving Credit Facility [Member] | MidCentral Energy Services [Member]
Line of Credit Facility [Line Items]
Line of credit maximum borrowing capacity			4,000,000
Line of credit current borrowing capacity			4,000,000
Outstanding balance of line of credit			3,400,000
Line of credit remaining borrowing capacity	$600,000
Required debt service coverage ratio	1.25
Revolving Credit Facility [Member] | Bank of Oklahoma Corporation National Prime Rate [Member]
Line of Credit Facility [Line Items]
Interest rates on debt instruments	4.00%

Factoring_Payable_Details

Factoring Payable (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Factoring Payable [Line Items]
Percentage of funding from factoring payable received upfront	90.00%
Percentage of balance of payables factored that is reserved	10.00%
Days till outstanding factored payable are repurchased	90 days
Factoring payable	$11,352	$13,152
London Interbank Offered Rate (LIBOR) [Member]
Factoring Payable [Line Items]
Interest margin on factoring payables	3.00%

Derivative_Contracts_Commodity

Derivative Contracts - Commodity Derivative Positions Oil Collars (Details) (Oil Collar [Member], 2015 [Member])	3 Months Ended
	Mar. 31, 2015
	bbl
Oil Collar [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	30,072
Floor Price (in usd per Bbl)	80
Ceiling Price (in usd per Bbl)	93.25

Derivative_Contracts_Commodity1

Derivative Contracts - Commodity Derivative Positions of Oil Collars - Three Way (Details) (Oil Collars - Three Way [Member], 2015 [Member])	3 Months Ended
	Mar. 31, 2015
	bbl
Oil Collars - Three Way [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	27,500
Sold Put (in usd per Bbl)	77.5
Purchased Put (in usd per Bbl)	92.5
Ceiling Price (in usd per Bbl)	102.6

Derivative_Contracts_Derivativ

Derivative Contracts Derivative Contracts - Commodity Derivative Positions Oil Fixed Price Swaps (Details) (Oil Swaps [Member])	3 Months Ended
	Mar. 31, 2015
	bbl
2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	30,080
Weighted Average Fixed Price (in usd per Bbl)	88.9
2016 [Member]
Derivative [Line Items]
Volumes (Bbls)	36,658
Weighted Average Fixed Price (in usd per Bbl)	86

Derivative_Contracts_Commodity2

Derivative Contracts - Commodity Derivative Positions Natural Gas Collars (Details) (Natural Gas Collars [Member], 2015 [Member])	3 Months Ended
	Mar. 31, 2015
	MMBTU
Natural Gas Collars [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (MMBtu)	976,356
Floor Price (in usd per MMBtu)	4
Ceiling Price (in usd per MMBtu)	4.32

Derivative_Contracts_Commodity3

Derivative Contracts - Commodity Derivative Positions Natural Gas Options (Details) (Natural Gas Options [Member])	3 Months Ended
	Mar. 31, 2015
	MMBTU
2015 [Member]
Derivative [Line Items]
Volumes (MMBtu)	620,040
Floor Price (in usd per MMBtu)	3.5
2016 [Member]
Derivative [Line Items]
Volumes (MMBtu)	930,468
Floor Price (in usd per MMBtu)	3.5

Derivative_Contracts_Commodity4

Derivative Contracts - Commodity Derivative Positions Natural Gas Swaps (Details) (Natural Gas Swaps [Member])	3 Months Ended
	Mar. 31, 2015
	MMBTU
2015 [Member]
Derivative [Line Items]
Volumes (MMBtu)	582,451
Weighted Average Fixed Price (in usd per MMBtu)	4.25
2016 [Member]
Derivative [Line Items]
Volumes (MMBtu)	629,301
Weighted Average Fixed Price (in usd per MMBtu)	4.37

Derivative_Contracts_Commodity5

Derivative Contracts - Commodity Derivative Positions Liquid Swaps (Details) (Natural Gas Liquid Swaps [Member], 2015 [Member])	3 Months Ended
	Mar. 31, 2015
	bbl
Natural Gas Liquid Swaps [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	62,213
Weighted Average Fixed Price (in usd per Bbl)	75.18

Derivative_Contracts_Offsettin

Derivative Contracts - Offsetting Commodity Derivative Assets and Liabilities (Details) (Commodity [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Derivative [Line Items]
Gross Amounts of Recognized Assets	$8,951	$10,127
Gross Amounts Offset	0	-61
Net Amounts Presented	8,951	10,066
Gross Amounts of Recognized Liabilities	0	61
Gross Amounts Offset	0	-61
Net Amounts Presented	0	0
Current Assets [Member]
Derivative [Line Items]
Gross Amounts of Recognized Assets	7,292	8,309
Gross Amounts Offset	0	-61
Net Amounts Presented	7,292	8,248
Long-term Assets [Member]
Derivative [Line Items]
Gross Amounts of Recognized Assets	1,659	1,818
Gross Amounts Offset	0	0
Net Amounts Presented	1,659	1,818
Current Liabilities [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities	0	61
Gross Amounts Offset	0	-61
Net Amounts Presented	0	0
Long-term Liabilities [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities	0	0
Gross Amounts Offset	0	0
Net Amounts Presented	$0	$0

Derivative_Contracts_Gains_Los

Derivative Contracts - Gains (Losses) on Derivative Contracts (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gain (loss) on derivative contracts, net	$1,224	($3,132)

Derivative_Contracts_Details

Derivative Contracts (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash received (paid) on settlement of derivative contracts	$2,339	($2,429)

Fair_Value_Measurements_Deriva

Fair Value Measurements - Derivative Assets and Contingent Consideration Measured at Fair Value (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	($2,843,000)	($2,517,000)
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			8,951,000
Contingent consideration				-23,330,000
Total				-13,264,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Contingent consideration				0
Total				0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			8,951,000
Contingent consideration				0
Total				10,066,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Contingent consideration				-23,330,000
Total				-23,330,000
Fair Value, Measurements, Recurring [Member] | Oil And Natural Gas Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			2,436,000
Fair Value, Measurements, Recurring [Member] | Oil And Natural Gas Collars [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Fair Value, Measurements, Recurring [Member] | Oil And Natural Gas Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			2,436,000
Fair Value, Measurements, Recurring [Member] | Oil And Natural Gas Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Fair Value, Measurements, Recurring [Member] | Natural Gas and NGL Puts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			1,035,000
Fair Value, Measurements, Recurring [Member] | Natural Gas and NGL Puts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Fair Value, Measurements, Recurring [Member] | Natural Gas and NGL Puts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			1,035,000
Fair Value, Measurements, Recurring [Member] | Natural Gas and NGL Puts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Fair Value, Measurements, Recurring [Member] | Oil, Natural Gas and NGL Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			5,480,000
Fair Value, Measurements, Recurring [Member] | Oil, Natural Gas and NGL Swaps [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Fair Value, Measurements, Recurring [Member] | Oil, Natural Gas and NGL Swaps [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			5,480,000
Fair Value, Measurements, Recurring [Member] | Oil, Natural Gas and NGL Swaps [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative			0
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				2,411,000
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				0
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				2,411,000
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				0
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				1,405,000
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				0
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				1,405,000
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				0
Fair Value, Measurements, Recurring [Member] | Oil Put Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				6,250,000
Fair Value, Measurements, Recurring [Member] | Oil Put Options [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				0
Fair Value, Measurements, Recurring [Member] | Oil Put Options [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				6,250,000
Fair Value, Measurements, Recurring [Member] | Oil Put Options [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				$0

Fair_Value_Measurements_Fair_V

Fair Value Measurements - Fair Value of Allocated Derivative Assets and Liabilities (Details) (Fair Value, Inputs, Level 3 [Member], USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014
Fair Value, Inputs, Level 3 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance	($2,517)
Loss on derivative contracts	-2,432
Cash paid upon settlement	2,106
Ending balance	-2,843
Unrealized losses included in earnings relating to derivatives held at period end	($702)

Fair_Value_Measurements_Detail

Fair Value Measurements (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Fair Value Disclosures [Abstract]
Outstanding balance of line of credit	$84,000	$83,000
Notes payable	$19,652	$20,424

Equity_Equity_Offering_Narrati

Equity - Equity Offering - Narrative (Details) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Apr. 29, 2014	Dec. 31, 2014
Class of Stock [Line Items]
Net proceeds from offering used to repay credit facility	$5
Common Units [Member]
Class of Stock [Line Items]
Issuance of common units in acquisitions (in units)		1,964,957
Common partnership units sold in public offering	3,450,000
Unit price of units sold in public offering	$23.25
Proceeds from public offering of common partnership units	76.2
Underwriter's fees associated with public sale of common units	3.6
Offering costs associated with public sale of common units	$0.30

Equity_Schedule_of_Distributio

Equity - Schedule of Distributions (Details) (USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions paid (in usd per unit)	$0.20	$0.58
Distributions	$3,312	$9,221
Common Units [Member]
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	3,312	7,852
Subordinated Units [Member]
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	0	1,279
General Partnership Units [Member]
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	$0	$90

Equity_Distribution_Narrative_

Equity - Distribution - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Distribution Made to Limited Partner [Line Items]
Distributions declared (in usd per unit)	$0.20
Days after quarter end in which distributions are declared and distributed	45 days
Class B Units [Member]
Distribution Made to Limited Partner [Line Items]
Distributions	$5,300,000

Allocation_of_Distributions_De

- Allocation of Distributions (Details) (USD $)	3 Months Ended
	Mar. 31, 2015
Minimum Quarterly Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	$16,116
Minimum [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	18,533
Minimum [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	20,145
Minimum [Member] | Third and Thereafter Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	24,174
Maximum [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	20,144
Maximum [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	$24,173
New Source Energy Partners LP [Member] | Minimum Quarterly Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	100.00%
New Source Energy Partners LP [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	85.00%
New Source Energy Partners LP [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	75.00%
New Source Energy Partners LP [Member] | Third and Thereafter Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	50.00%
Class B [Member] | Minimum Quarterly Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	0.00%
Class B [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	15.00%
Class B [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	25.00%
Class B [Member] | Third and Thereafter Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	50.00%

Equity_Noncontrolling_Interest

Equity - Noncontrolling Interest - Narrative (Details) (Class B Units [Member])	3 Months Ended
	Mar. 31, 2015
First Target Distribution [Member]
Class of Stock [Line Items]
Increasing distribution percentage associated with Class B Units	15.00%
Second Target Distribution [Member]
Class of Stock [Line Items]
Increasing distribution percentage associated with Class B Units	25.00%
Third and Thereafter Target Distribution [Member]
Class of Stock [Line Items]
Increasing distribution percentage associated with Class B Units	50.00%

Equity_Equity_Compensation_Nar

Equity - Equity Compensation - Narrative (Details) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Jun. 26, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	$3,861,000	$258,000
Phantom Units [Member] | Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	2,300,000
Phantom Units [Member] | Common Units [Member] | Early Vesting [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense	900,000
Phantom Units [Member] | Common Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units granted (in units)			432,038
Value of phantom units granted			10,100,000
Maximum [Member] | Phantom Units [Member] | Common Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom unit vesting period			2 years
Service Requirement Units [Member] | Phantom Units [Member] | Common Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units granted (in units)			401,171
Fair Market Value Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units granted (in units)	242,753
Common units vested (in units)	219,439
Equity-based compensation expense	$1,500,000

Earnings_per_Unit_Earnings_Per

Earnings per Unit - Earnings Per Unit (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units excluded from EPS calculation because of antidilutive effect	32,542
Net loss	($57,172)	($1,531)
Common Stock Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	-49,574	-1,241
Weighted average units outstanding	16,346,317	9,919,926
Basic and diluted income per unit (in usd per unit)	($3.03)	($0.12)
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	-7,128	-271
Weighted average units outstanding	2,205,000	2,205,000
Basic and diluted income per unit (in usd per unit)	($3.23)	($0.12)
General Partnership Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	($470)	($19)
Weighted average units outstanding	155,102	155,102
Basic and diluted income per unit (in usd per unit)	($3.03)	($0.12)

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	3 Months Ended		12 Months Ended	0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Jan. 09, 2015	Feb. 24, 2015	Jan. 12, 2015
Related Party Transaction [Line Items]
Leasehold cost obligations	$200,000		$400,000
Charges and fees due to related parties	266,000		2,318,000
General and administrative expense	12,234,000	5,560,000
General Partner [Member]
Related Party Transaction [Line Items]
General and administrative expense	30,000	300,000
Professional fees paid	200,000		2,300,000
Board of Directors Chairman [Member]
Related Party Transaction [Line Items]
Ownership percentage of reporting company	25.00%
Percentage of common stock owned	15.60%					15.60%
Percentage of subordinate units owned	100.00%
Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Percentage of common stock owned	5.00%
New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related party receivables	4,400,000		3,400,000
Chief Financial Officer [Member]
Related Party Transaction [Line Items]
Professional fees paid	100,000	100,000
Ownership percentage in Finley & Cook	31.50%
General Partner [Member] | Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Ownership percentage of reporting company	69.40%
Subordinated Units [Member] | Board of Directors Chairman [Member]
Related Party Transaction [Line Items]
Number of subordinate units owned	2,205,000
MCCS [Member]
Related Party Transaction [Line Items]
Liability assumed in acquisition	700,000
MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired				2
Sales of real property				900,000
Canadian County, OK [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired				1
Ector County, TX [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired				1
Karnes, Texas [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Sales of real property					500,000
President [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Ownership percentage				50.00%
President [Member] | MidCentral Energy Services [Member] | Karnes, Texas [Member]
Related Party Transaction [Line Items]
Ownership percentage					33.00%
Chief Executive Officer [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired				3
Ownership percentage				50.00%
Real estate land, carrying value					$600,000
Chief Executive Officer [Member] | MidCentral Energy Services [Member] | Karnes, Texas [Member]
Related Party Transaction [Line Items]
Ownership percentage					67.00%

Related_Party_Transactions_Sum

Related Party Transactions - Summary of Related Party Transactions (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Related Party Transaction [Line Items]
Related Party Costs	$1,015	$799
Producing Overhead Charges [Member] | New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related Party Costs	733	375
Drilling And Completion Overhead Charges [Member] | New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related Party Costs	38	9
Saltwater Disposal Fees [Member] | New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related Party Costs	$244	$415

Property_Plant_and_Equipment_N

Property, Plant and Equipment - Narrative (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Property, Plant and Equipment [Abstract]
Impairment of oil and natural gas properties	$43,119	$0

Property_Plant_and_Equipment_S

Property, Plant and Equipment - Schedule of Property and Equipment (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]
Property and equipment, net	$72,744	$68,886
Iron [Member]
Property, Plant and Equipment [Line Items]
Total	13,390	12,258
Oilfield Services [Member]
Property, Plant and Equipment [Line Items]
Total	78,790	73,659
Less: accumulated depreciation	-7,247	-4,773
Property and equipment (excluding land), net	71,543	68,886
Land	1,201	0
Property and equipment, net	72,744	68,886
Oilfield Services [Member] | Vehicles and Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	16,165	15,891
Oilfield Services [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	47,717	44,441
Oilfield Services [Member] | Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	$1,518	$1,069

Commitments_and_Contingencies_

Commitments and Contingencies (Details) (USD $)	0 Months Ended
	Jan. 29, 2015	Mar. 31, 2015	Jun. 26, 2014		Jan. 12, 2015
Loss Contingencies [Line Items]
Estimated contingency loss		$250,000
Pending Litigation [Member]
Loss Contingencies [Line Items]
Pending litigation, amount	1,900,000
MidCentral Energy Services [Member]
Loss Contingencies [Line Items]
Contingent consideration		6,300,000
MCCS [Member]
Loss Contingencies [Line Items]
Contingent consideration		4,100,000	4,057,000	[1]
EFS and RPS [Member]
Loss Contingencies [Line Items]
Contingent consideration		23,300,000	21,984,000	[2]
Percentage of contingent consideration to be paid in cash		50.00%
Receivable due from prior owners		1,000,000
Percentage of contingent consideration to be paid in common units		50.00%
Maximum [Member] | MidCentral Energy Services [Member]
Loss Contingencies [Line Items]
Contingent consideration		120,000,000
Maximum [Member] | MCCS [Member]
Loss Contingencies [Line Items]
Contingent consideration		$4,500,000	$4,500,000
Board of Directors Chairman [Member]
Loss Contingencies [Line Items]
Percentage of common stock owned		15.60%			15.60%
Affiliated Entity [Member]
Loss Contingencies [Line Items]
Percentage of common stock owned					30.60%
[1]	The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 12 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
[2]	The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 12 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.

Asset_Retirement_Obligations_C

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at January 1, 2015	$3,681
Liability incurred upon acquiring and drilling wells	0
Accretion	74	68
Asset retirement obligation at March 31, 2015	3,755
Less current portion	116
Asset retirement obligations, net of current	$3,639		$3,568

Business_Segment_Information_D

Business Segment Information (Details)	3 Months Ended
	Mar. 31, 2015
	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, 2015		Mar. 31, 2014		Dec. 31, 2014
Segment Reporting Information [Line Items]
Revenue	$38,117		$27,427
Direct operating expenses	27,425		9,948
Segment margin	10,692		17,479
Depreciation, depletion, amortization and accretion	12,421		9,347
Impairment of oil and natural gas properties	43,119		0
General and administrative	12,234		5,560
Operating (loss) income	-57,082		2,572
Capital expenditures	7,117	[1]	13,215	[1]
Total assets	315,533	[2]			375,546
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenue	6,567		18,851
Direct operating expenses	4,366		5,382
Segment margin	2,201		13,469
Depreciation, depletion, amortization and accretion	4,794		5,887
Impairment of oil and natural gas properties	43,119
General and administrative	4,569		3,843
Operating (loss) income	-50,281		3,739
Capital expenditures	1,014	[1]	10,072	[1]
Total assets	149,200				199,178
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Revenue	31,550		8,576
Direct operating expenses	23,059		4,566
Segment margin	8,491		4,010
Depreciation, depletion, amortization and accretion	7,627		3,460
Impairment of oil and natural gas properties	0
General and administrative	7,665		1,717
Operating (loss) income	-6,801		-1,167
Capital expenditures	6,103	[1]	3,143	[1]
Total assets	$166,333				$176,368
[1]	On an accrual basis and exclusive of acquisitions.
[2]	Exploration and Production includes impairment of oil and natural gas properties of $43.1 million as discussed in Note 10 "Property, Plant and Equipment."

Subsequent_Events_Details

Subsequent Events (Details) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	6-May-15	Apr. 27, 2015	8-May-15	1-May-15
Subsequent Event [Line Items]
Estimated offering costs	$0	$100,000
Distributions declared (in usd per unit)	$0.20
Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions declared (in usd per unit)			$0.20
General Partner [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Conversion of general partner units to common units				155,102
Series A Cumulative Convertible Preferred Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Dividend rate					11.00%
Conversion ratio of preferred units					3.7821
Public offering of units					44,000,000
Unit price (in usd per unit)					$25
Increase in distribution rate					2.00%
Proceeds from public offering					40,000,000
Underwriting discounts					3,000,000
Estimated offering costs					1,000,000
Option period for underwrites to purchase additional units (in units)					30 days
Additional units available to underwriters (in units)					264,000,000
Deylau [Member] | General Partner [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Ownership interest				69.40%
Transfer of ownership interest				26.50%
Transfer of ownership presented as percentage of general partner ownership interest				18.40%
Sale of oil and gas assets to subsidiary				150,000,000
2100 Energy LLC [Member] | General Partner [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Transfer of ownership presented as percentage of general partner ownership interest				51.00%
Revolving Credit Facility [Member] | Eighth Amendment [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Cap on cash distributions						$6,000,000
Percentage of outstanding balance to be paid off before distributions to common unit (90% or less)						90.00%
Maximum [Member] | Series A Cumulative Convertible Preferred Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Dividend rate					20.00%

Subsequent_Events_Schedule_of_

Subsequent Events - Schedule of Distributions (Details) (USD $)	3 Months Ended		0 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	6-May-15
Subsequent Event [Line Items]
Distributions	$3,312	$9,221
Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions			3,312
Common Units [Member]
Subsequent Event [Line Items]
Distributions	3,312	7,852
Common Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions			3,312
Subordinated Units [Member]
Subsequent Event [Line Items]
Distributions	0	1,279
Subordinated Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions			0
General Partnership Units [Member]
Subsequent Event [Line Items]
Distributions	0	90
General Partnership Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions			$0