New Source Energy Partners (NSLP) 10-K 20 Mar 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Jun. 30, 2014	Mar. 06, 2015
Document Information [Line Items]
Entity Registrant Name	New Source Energy Partners L.P.
Document Type	10-K
Current Fiscal Year End Date	-19
Entity Public Float		$208.40
Amendment Flag	FALSE
Entity Central Index Key	1560443
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	30-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Common Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding			16,403,134
Subordinated Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding			2,205,000
General Partnership Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding			155,102

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash	$5,504	$7,291
Restricted cash	350	0
Accounts receivable, net	38,784	12,609
Derivative contracts	8,248	130
Inventory	4,236	162
Other current assets	3,116	822
Total current assets	60,238	21,014
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	332,413	291,829
Less: Accumulated depreciation, depletion, and amortization	-153,734	-128,961
Total oil and natural gas properties, net	178,679	162,868
Property and equipment, net	68,886	8,166
Intangible assets, net	56,377	35,009
Goodwill	9,315	23,974
Derivative contracts	1,818	660
Other assets	2,152	3,019
Total assets	377,465	254,710
Current liabilities:
Accounts payable and accrued liabilities	15,326	3,267
Accounts payable-related parties	4,237	8,221
Factoring payable	13,152	1,907
Contingent consideration payable	11,572	0
Derivative contracts	0	3,167
Asset retirement obligations	113	0
Current portion of long-term debt	11,825	719
Total current liabilities	56,225	17,281
Long-term debt	95,218	80,014
Contingent consideration payable	10,801	6,320
Asset retirement obligations	3,568	3,455
Other liabilities	339	387
Total liabilities	166,151	107,457
Commitments and contingencies (Note 15)
Unitholders' equity:
Common units (16,160,381 units issued and outstanding at December 31, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	231,510	151,773
Common units held in escrow	-6,955	0
Subordinated units (2,205,000 units issued and outstanding at December 31, 2014 and December 31, 2013)	-28,717	-17,334
General partner's units (155,102 units issued and outstanding at December 31, 2014 and December 31, 2013)	-1,944	-1,174
Total New Source Energy Partners L.P. unitholders' equity	193,894	133,265
Noncontrolling interest	17,420	13,988
Total unitholders' equity	211,314	147,253
Total liabilities and unitholders' equity	$377,465	$254,710

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parentheticals)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common units outstanding (in units)	16,160,381	9,599,578
Common units issued (in units)	16,160,381	9,599,578
Subordinated units outstanding (in units)	2,205,000	2,205,000
Subordinated units issued (in units)	2,205,000	2,205,000
General partner's capital units outstanding (in units)	155,102	155,102
General partner's capital units, issued (in units)	155,102	155,102

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues:
Oil sales	$14,906		$8,090		$5,570
Natural gas sales	15,534		10,000		6,030
NGL sales	31,048		28,847		23,996
Oilfield services	104,155		3,738		0
Total revenues	165,643		50,675		35,596
Operating costs and expenses:
Oil, natural gas and NGL production	18,617		12,631		6,217
Production taxes	2,833		2,669		1,144
Cost of providing oilfield services	60,904		2,040		0
Depreciation, depletion and amortization	54,352		18,556		14,409
Accretion	327		209		116
Impairment of goodwill and other intangible assets	59,000		0		0
General and administrative	28,671		14,760	[1]	12,660
Change in fair value of contingent consideration	-9,031		-1,600		0
Total operating costs and expenses	215,673		49,265		34,546
Operating (loss) income	-50,030		1,410		1,050
Other income (expense):
Interest expense	-5,041		-4,078		-3,202
Gain (loss) on derivative contracts, net	10,707	[2]	-5,548	[2]	7,057	[2]
Gain on investment in acquired business	2,298		22,709		0
Other (expense) income	-9		3		0
(Loss) income before income taxes	-42,075		14,496		4,905
Income tax benefit (expense)	0		12,126		-1,796
Net (loss) income	-42,075		26,622		3,109
Less: net income attributable to noncontrolling interest	242		0		0
Net (loss) income	-42,317		26,622		3,109
General Partnership Units [Member]
Other income (expense):
Net (loss) income	-409
Net (loss) income per unit:
Basic and diluted income per unit (in usd per unit)	($2.64)		$1.88
Subordinated Units [Member]
Other income (expense):
Net (loss) income	-6,256
Net (loss) income per unit:
Basic and diluted income per unit (in usd per unit)	($2.84)		$1.86
Common Units [Member]
Other income (expense):
Net (loss) income	($35,652)
Net (loss) income per unit:
Basic and diluted income per unit (in usd per unit)	($2.64)		$2.42
[1]	Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.
[2]	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.

Consolidated_Statements_of_Uni

Consolidated Statements of Unitholders' Equity (USD $)	Total	Parent Net Investment [Member]	Common Units [Member]	Subordinated Units [Member]	General Partnership Units [Member]	Noncontrolling Interest [Member]	Common Stock [Member]
In Thousands, except Share data, unless otherwise specified
Beginning Balance at Dec. 31, 2011		$18,420
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income		3,109
Equity-based compensation		8,204
Distribution to parent		-13,758
Increase (Decrease) in Partners' Capital [Roll Forward]
Net loss	3,109
Ending Balance at Dec. 31, 2012	0
Ending Balance at Dec. 31, 2012		15,975
Increase (Decrease) in Temporary Equity [Roll Forward]
Net income		5,303
Distribution to parent		-2,495
Ending Balance at Feb. 12, 2013
Beginning Balance at Dec. 31, 2012	0		0	0	0	0
Beginning Balance at Dec. 31, 2012		15,975
Beginning Balance (in units) at Dec. 31, 2012			0	0	0
Increase (Decrease) in Temporary Equity [Roll Forward]
Equity-based compensation		388
Subordinated note payable to parent at closing		25,000
Cash paid to parent at closing		-15,800
Distribution of accounts receivable to parent		-7,014
Accounts payable assumed by parent		1,742
Purchase of oil and natural gas properties from NSEC in exchange for units		26,901
Increase (Decrease) in Partners' Capital [Roll Forward]
Purchase of oil and natural gas properties from NSEC in exchange for units (in units)			777,500	2,205,000	150,000
Purchase of oil and natural gas properties from NSEC in exchange for units	-26,901		-7,306	-18,347	-1,248
Issuance of common units, net of offering costs (in units)			4,250,000
Issuance of common units, net of offering costs	76,565		76,565
Issuance to general partner from overallotment exercised					5,102
Equity-based compensation (in units)			367,500
Equity-based compensation	7,451		7,451
Purchases of oil and natural gas properties in exchange for units (in units)			1,792,545
Purchases of oil and natural gas properties in exchange for units	36,406		36,406
Distributions to unitholders	-12,780		-9,477	-3,086	-217
Issuance of common units in acquisitions (in units)			1,947,033
Issuance of common units in acquisitions	35,360		21,372			13,988
Issuance of common units in private placement, net of offering costs (in units)							465,000
Issuance of common units in private placement, net of offering costs	9,833						9,833
Net loss	26,622
Ending Balance at Dec. 31, 2013	147,253		151,773	-17,334	-1,174	13,988
Ending Balance (in units) at Dec. 31, 2013			9,599,578	2,205,000	155,102
Beginning Balance at Feb. 12, 2013
Increase (Decrease) in Partners' Capital [Roll Forward]
Net loss	21,319			4,099	291		16,929
Ending Balance at Dec. 31, 2013	147,253		151,773	-17,334	-1,174	13,988
Ending Balance (in units) at Dec. 31, 2013			9,599,578	2,205,000	155,102
Increase (Decrease) in Partners' Capital [Roll Forward]
Issuance of common units, net of offering costs (in units)			4,170,000
Issuance of common units, net of offering costs	92,375		92,375
Equity-based compensation (in units)			425,846
Equity-based compensation	3,233		3,233
Distributions to unitholders	-36,742		-31,012	-5,127	-361	-242
Issuance of common units in acquisitions (in units)			1,964,957
Issuance of common units in acquisitions	47,370		43,938			3,432
Net loss	-42,075		-35,652	-6,256	-409	242
Offering cost related to 2013 private placement paid in 2014	-100		-100
Ending Balance at Dec. 31, 2014	$211,314		$224,555	($28,717)	($1,944)	$17,420
Ending Balance (in units) at Dec. 31, 2014			16,160,381	2,205,000	155,102

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flow (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Cash Flows from Operating Activities:
Net (loss) income	($42,075)		$26,622		$3,109
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	54,352		18,556		14,409
Accretion	327		209		116
Impairment of goodwill and other intangible assets	59,000		0		0
Amortization of deferred loan costs	660		479		603
Write off of loan costs due to debt refinancing	167		1,436		0
Equity-based compensation	3,233		7,839		8,204
Deferred income tax benefit	0		-12,024		1,694
Change in fair value of contingent consideration	-9,031		-1,600		0
Gain on investment in acquired business	-2,298		-22,709		0
(Gain) loss on derivative contracts, net	-10,707	[1]	5,548	[1]	-7,057	[1]
Cash (paid) received on settlement of derivative contracts	-1,773		-1,929		5,987
Payments for premiums on derivatives	0		-1,334		0
Other	582		0		0
Changes in operating assets and liabilities:
Accounts receivable	-2,859		-10,595		881
Other current assets and other assets	-4,122		333		0
Accounts payable and accrued liabilities	-547		7,533		-147
Net cash provided by operating activities	44,909		18,364		27,799
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	-63,446		-22,102		0
Additions to oil and natural gas properties	-24,671		-28,921		-12,162
Additions to other property and equipment	-11,536		0		0
Net cash used in investing activities	-99,653		-51,023		-12,162
Cash Flows from Financing Activities:
Proceeds from borrowings	22,369		80,500		3,000
Payments on borrowings	-19,814		-70,102		-3,500
Payment on subordinated note payable to parent	0		-25,000		0
Payments for deferred loan costs	-536		-1,954		-64
(Payments on) proceeds from factoring payable, net	-4,595		229		0
Proceeds from sales of common units, net of offering costs	92,375		77,880		0
Proceeds from issuance of common units in private placement, net of offering costs	0		9,833		0
Payments of offering costs	-100		-361		-1,315
Distribution to unitholders	-36,742		-12,780		0
Distribution to NSEC	0		-18,295		-13,758
Net cash provided by (used in) financing activities	52,957		39,950		-15,637
Net change in cash and cash equivalents	-1,787		7,291		0
Cash and cash equivalents, beginning of period	7,291		0		0
Cash and cash equivalents, end of period	5,504		7,291		0
Supplemental Cash Flow Information:
Cash paid for interest	4,340		2,061		2,553
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation	-100		1,735		-17
(Decrease) increase in accrued capital expenditures	355		3,030		-780
Accounts receivable distributed to NSEC	0		-7,014
Accounts payable assumed by NSEC	0		-1,742		-172
Subordinated note issued to NSEC for oil and natural gas properties	0		25,000		0
Common units issued in connection with acquisitions	-46,239		-57,778		0
Acquisition of property and equipment by financing	7,580		0		0
Factoring payables assumed in connection with acquisitions	15,840		0		0
Debt assumed in connection with acquisitions	$17,571		$0		$0
[1]	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies
	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.
	On February 13, 2013, the Partnership completed its initial public offering (the “Offering”) of 4,000,000 common units representing limited partner interests in the Partnership. From the proceeds of the Offering, the Partnership made a cash distribution of $15.8 million to NSEC as consideration (together with its issuance to NSEC of what then constituted approximately 50% of New Source Energy GP, LLC, which owns all of the Partnership general partner units, 777,500 common units, 2,205,000 subordinated units and a $25.0 million note payable) in exchange for the contribution by NSEC of the IPO Properties and certain commodity derivative contracts. Additionally, the Partnership assumed approximately $70.0 million of NSEC's indebtedness previously secured by the IPO Properties, and used a portion of the net proceeds from the Offering to repay in full this assumed debt at the closing of the Offering.
	Basis of Presentation. The acquisition of the IPO Properties discussed above was a transaction between businesses under common control. The accounts relating to the IPO Properties have been reflected retroactively in the Partnership’s financial statements at carryover basis. As such, for periods prior to the Offering, the accompanying financial statements have been prepared on a "carve-out" basis from NSEC's financial statements and reflect the historical accounts directly attributable to the IPO Properties together with allocations of expenses from NSEC. Therefore, for periods prior to February 13, 2013, the accompanying consolidated financial statements may not be indicative of the Partnership’s future performance and may not reflect what its financial position, results of operations, and cash flows would have been had it been operated as an independent company during the periods presented. Prior to February 13, 2013, NSEC performed certain corporate functions on behalf of the IPO Properties, and the consolidated financial statements reflect an allocation of the costs NSEC incurred. These functions included executive management, information technology, tax, insurance, accounting, legal and treasury services. The costs of such services were allocated based on the most relevant allocation method to the service provided, primarily based on relative book value of assets, among other factors. Management believes such allocations are reasonable; however, they may not be indicative of the actual expense that would have been incurred had the Partnership been operated as an independent company for all of the periods presented. The charges for these functions are included primarily in general and administrative expenses.
	NSEC became the owner of the IPO Properties on August 12, 2011 and reflected the IPO Properties in its financial statements retroactively because the acquisition of the IPO Properties was a transaction between businesses under common control. Prior to that date, the IPO Properties were owned by a nontaxable entity. NSEC was a taxable entity. Accordingly, on August 12, 2011, NSEC accrued deferred income taxes attributable to differences in the book and tax bases in the IPO Properties and subsequent to the August 12, 2011 acquisition has accounted for income taxes using the asset and liability method until the Offering. The Partnership is not a taxable entity. Accordingly, when NSEC contributed the IPO Properties to the Partnership in 2013, the Partnership reversed the related deferred income taxes, and subsequently the Partnership will not reflect income taxes in its financial statements.
	Principles of Consolidation. The 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.
	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 or working capital.
	Use of Estimates. The preparation of the Partnership’s consolidated financial statements in conformity with 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, fair values of reporting units used in goodwill impairment testing, fair values of other intangible assets used in recording impairments and asset retirement obligations. Actual results could differ from those estimates.
	Cash and Cash Equivalents. The Partnership considers all highly liquid investments (i.e., investments which, when purchased, have original maturities of three months or less) to be cash equivalents. Cash is held at financial institutions that are insured by the FDIC. At times, the balance may exceed the federally insured limits.
	Accounts Receivable and Allowances. Accounts receivable include amounts for sales of oil, natural gas and NGL, as well as amounts due from customers for services performed. The Partnership grants credit to its customers in the ordinary course of business and generally does not require collateral. Customer balances are considered delinquent if unpaid 90 days following the invoice date, and credit privileges may be revoked if balances remain unpaid. Accounts receivable are reviewed and an estimate for losses is provided through an allowance for doubtful accounts when deemed appropriate. In evaluating the level of established reserves, we make judgments regarding our customers’ ability to make required payments, economic events and other factors. As the financial condition of customers changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event we were to determine that a customer may not be able to make required payments, we would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made that they will not be collected.
	Accounts receivable consist of the following as of December 31, 2014 and 2013 (in thousands):
		2014			2013
	Oil, natural gas and NGL sales	$	6,710		$	8,417
	Oil, natural gas and NGL sales - related parties	1,546			228
	Oilfield services	30,668			3,964
		38,924			12,609
	Less: allowance for doubtful accounts	(140		)	—
	Total accounts receivable, net	$	38,784		$	12,609
	Based on management’s assessment of credit history with customers having outstanding balances and current relationships with them, it has concluded that an allowance of $0.1 million was necessary as of December 31, 2014. No allowance for doubtful accounts was deemed necessary as of December 31, 2013. From time to time, the Partnership may factor its accounts receivable. As part of the factoring arrangement, certain receivables are pledged as collateral. See "Note 5 - Factoring Payable" for additional information regarding our factoring arrangements.
	Inventory. Inventory is stated at the lower of cost or market value, determined on an average cost basis. Inventories consist of consumable materials used during the performance of services and are available for resale. The Partnership assesses the realizability of its inventories based on specific usage and future utility. A charge to cost of sales is taken when factors that would result in a need for reduction in valuation, such as excess or obsolete inventory, are determined. No allowance for obsolescence was deemed necessary as of December 31, 2014 or 2013.
	Fair Value of Financial Instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Additionally, GAAP requires the use of valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The carrying amounts reflected in the balance sheet for cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and factoring payable approximate the respective fair values due to the short maturities of those instruments. Other financial instruments consist of long-term obligations. The fair value of long-term obligations is estimated based on current interest rates offered to the Partnership for obligations with similar remaining maturities (Level 2). The recorded value of these financial instruments approximated fair value at December 31, 2014 and 2013. See "Note 7 - Fair Value Measurements" for further discussion of our fair value measurements.
	Fair Value of Non-financial Assets and Liabilities. We also apply fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil, natural gas, and NGL production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. We may use the present value of estimated future cash inflows and/or outflows or third-party offers to value non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in "Note 7 - Fair Value Measurements."
	Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to expected oil, natural gas and NGL production, we enter into oil, natural gas and NGL derivative contracts. We recognize our derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. We have elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, account for our commodity derivative contracts at fair value with changes in fair value reported currently in earnings. We net derivative assets and liabilities whenever we have a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of our derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statement of cash flows. See "Note 6 - Derivative Contracts" for further discussion of our derivatives.
	Oil and Natural Gas Operations. 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, natural gas and NGL reserves are capitalized into a full cost pool. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
	Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down is not reversible at a later date. The ceiling limitation calculation is prepared using the 12-month oil, natural gas, and NGL average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil, natural gas, and NGL. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although we have not designated any of our derivative contracts as cash flow hedges and have therefore not included our derivative contracts in estimating future cash flows.
	When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas properties for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
	Property and Equipment. Property and equipment is recorded at cost, net of accumulated depreciation. The cost of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the year of disposal. The Partnership calculates depreciation expense using the straight-line method over the assets’ estimated useful lives, which are as follows:
		Estimated Useful Life (in years)
	Vehicles and trailers	3	-	10
	Machinery and equipment	3	-	20
	Office equipment	3	-	7
	Rental irons			10
	Leasehold improvements (1)	3	-	10
	_______________
	(1) Leasehold improvements are depreciated on the straight-line basis over the remaining months of the applicable lease.
	Expenditures for major additions and improvements are capitalized, while minor replacements, maintenance, and repairs that do not improve or extend the life of such assets, are charged to operations as incurred.
	Impairment of Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset or asset group to the forecast of undiscounted estimated future net cash flows expected to be generated by the asset or asset group. If such assets are considered to be impaired, the impairment to be recognized is the amount by which the carrying amount of the asset or asset group exceeds our forecast of the discounted estimated future net cash flows directly related to the asset or asset group including disposal value, if any.
	We make estimates and judgments about future undiscounted cash flows and fair values. Although our cash flow forecasts are based on assumptions that are consistent with our plans, there is a significant degree of judgment involved in determining the cash flows attributable to a long-lived asset over its estimated remaining useful life. Our estimates of anticipated cash flows could be reduced significantly in the future and as a result, the carrying amounts of our long-lived assets could be subject to impairment charges in the future.
	Intangible Assets. As part of the acquisition of MCE in November 2013 and acquisitions of MidCentral Completion Services, LLC (“MCCS”), Erick Flowback Services LLC ("EFS") and Rod’s Production Services L.L.C. ("RPS") in June 2014, intangible assets for customer relationships and non-compete agreements were identified and recognized. Amortization for the customer relationship intangible assets was computed using an accelerated method over seven years similar to the expected cash flow pattern of the acquired customer relationships. Amortization for the non-compete agreement intangible asset was based on a straight-line approach over the agreement period. See "Note 8 - Goodwill and Intangible Assets" for additional discussion of our intangible assets and impairment assessment performed in the fourth quarter of 2014.
	Goodwill. In conjunction with the acquisitions of MCE, MCCS, EFS and RPS, the Partnership recorded goodwill, which represents the consideration the Partnership paid in excess of the fair value of identifiable assets in the acquisitions. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of November 1 for MCE and April 1 for MCCS, EFS and RPS, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. See "Note 8 - Goodwill and Intangible Assets" for additional discussion of goodwill and impairment assessment performed in the fourth quarter of 2014.
	Debt Issuance Costs. We amortize debt issuance costs related to our long-term debt as interest expense over the scheduled maturity period of the related debt. We include unamortized debt issuance costs in other assets in the consolidated balance sheet. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.
	Contingent Consideration. Contingent consideration, which represents earn out payments in connection with certain of the Partnership’s acquisitions, is recognized at fair value on the acquisition date and remeasured each reporting period with subsequent adjustments to fair value included in general and administrative expenses in the accompanying consolidated statements of operations. The Partnership estimates the fair value of contingent consideration liabilities based on certain performance milestones of the acquired companies or properties, and estimated probabilities of achievement, then discounts the liabilities to present value using the Partnership’s cost of debt. Contingent consideration is valued using significant inputs that are not observable in the market which are defined as Level 3 inputs pursuant to fair value measurement accounting. The Partnership believes its estimates and assumptions are reasonable; however, there is significant judgment involved.
	Changes in the fair value of contingent consideration liabilities may result from changes in discount periods, changes in the timing and amount of sales and/or other specific milestone estimates and changes in probability assumptions with respect to the likelihood of achieving the various earn out criteria. These changes could cause a material impact to, and volatility in our operating results. Earn out payments, if any, will be reflected in cash flows from financing activities and the changes in fair value are reflected in cash flows from operating activities in the consolidated statements of cash flows. See "Note 3 - Contingent Consideration" for additional discussion of our contingent consideration obligations.
	Asset Retirement Obligations. We own oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statement of operations. We determine our asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See "Note 13 - Asset Retirement Obligations" for further discussion of our asset retirement obligations.
	Revenue Recognition. All revenue is recognized when persuasive evidence of an arrangement exists, the product or service has been provided, the amount is fixed or determinable and collectability is reasonably assured.
	Oil, natural gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil, natural gas, and NGL sales such that revenues are recognized based on the actual proceeds from the oil, natural gas, and NGL sold to purchasers. Oil, natural gas, and NGL imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. For the years ended December 31, 2014 and 2013, there were no significant oil, natural gas, and NGL imbalances.
	Pressure testing services are provided under master service agreements with our customers. Services are typically provided on a day rate or hourly basis. Jobs for these services are typically short-term in nature and range from a few hours to a few days. Revenue is recognized as the services are performed based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and the personnel involved in such services or mobilization. Additional revenue is generated through the sale of consumable supplies that are incidental to the service being performed. The use of consumable supplies is reflected on completed field tickets and billed with the services, as discussed above.
	Equity-Based Compensation. The Partnership awards common units under its long-term incentive plan. The related expenses reflected in the financial statements are based on the fair value of the Partnership’s equity instruments as of the grant date fair value of those instruments. That cost is recognized as compensation expense over the requisite service period (generally the vesting period).
	Deferred Compensation Plans. In 2014, the Board of Directors of our general partner approved a 401(k) retirement plan for our employees. Under the plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service (“IRS”). For the year ended December 31, 2014, the Company made matching contributions to the plan equal to 100% on the first 3% of employee deferred wages. Retirement plan expense for the years ended December 31, 2014 was approximately $0.3 million.
	Income Taxes. Income taxes are reflected in these consolidated financial statements during the periods in which the IPO Properties were owned by a taxable entity. Since the Partnership is not a taxable entity, no income taxes have been provided for the periods following completion of the Offering. Upon the Partnership becoming a non-taxable entity, the Partnership recognized a tax benefit related to the change in tax status of approximately $12.1 million for the year ended December 31, 2013.
	We are a limited partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Partnership are passed through to its unitholders. Limited partnerships are subject to Texas margin tax.
	Accounting Standards Codification (“ASC”) Topic 740, Income Taxes, which clarifies the accounting for uncertainties in income taxes recognized in the financial statements, provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of ASC 740 and in subsequent periods. As of and for the years ended December 31, 2014 and 2013, the Partnership did not have any uncertain tax positions, and therefore no adjustments have been made to the financial statements. The tax years 2011 – 2013 remain open to examination for federal income tax purposes. MCES’ income tax returns for the period ended November 12, 2013 and the year ended December 31, 2012 remain subject to potential examination by major tax jurisdictions. Prior to 2012, all entities were single-member LLC’s and were disregarded for tax purposes.
	Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership's book basis in its net assets exceeds the Partnership's net tax basis by $111.2 million at December 31, 2014.
	Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when an EA and/or remediation activities are probable and costs can be reasonably estimated. See "Note 15 - Commitments and Contingencies" for discussion of our commitments and contingencies.
	Concentration of Risk. Our derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating.
	A default by the Partnership under its senior secured revolving credit facility (the “credit facility”) constitutes a default under its derivative contracts with its counterparty that is also a lender under the credit facility. We have master netting agreements with our derivative counterparties, which allow us to net our derivative assets and liabilities with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.
	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 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 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.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	Acquisitions
	The Partnership completed acquisitions during 2013 and 2014, as described below. Certain of the 2013 acquisitions increased the Partnership's portfolio of oil and natural gas properties. The acquisitions of MCE, EFS, RPS and MCCS established the Partnership's oilfield services segment. With the exception of the acquisition of oil and natural gas properties from Orion Exploration Partners, LLC, all of the 2013 acquisitions were with related parties. The acquisition of MCCS was the only acquisition in 2014 with related parties. See "Note 11 - Related Party Transactions."
	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 7 - 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.
	2013 Acquisitions
	March 2013 Acquisition. In March 2013, we acquired certain oil and natural gas properties located in the Golden Lane and Luther fields in Oklahoma from NSEC, Scintilla, and W.K. Chernicky, LLC, for an aggregate adjusted purchase price of approximately $28.0 million (the "March 2013 Acquisition"). As consideration, the Partnership issued 1,378,500 common units valued at $20.30 per unit.
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	29,049
	Other assets	754
	Asset retirement obligations	(1,333		)
	Other liabilities	(488		)
	Total net assets	$	27,982
	May 2013 Acquisition. In May 2013, the Partnership completed an acquisition of certain oil and natural gas properties located in Oklahoma from NSEC for approximately $7.9 million, net of purchase price adjustments (the "May 2013 Acquisition").
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	8,165
	Asset retirement obligations	(19		)
	Other liabilities	(254		)
	Total net assets	$	7,892
	July 2013 Acquisition. In July 2013, the Partnership completed an acquisition of a 10% working interest in certain oil and natural gas properties located in Oklahoma from Scintilla for approximately $4.9 million, net of purchase price adjustments (the "July 2013 Acquisition").
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	4,888
	Asset retirement obligations	(4		)
	Other liabilities	(18		)
	Total net assets	$	4,866
	Orion Acquired Properties. In July 2013, the Partnership acquired certain oil and natural gas properties located in Oklahoma from Orion Exploration Partners, LLC for approximately $3.2 million, net of purchase price adjustments (the "Orion Acquired Properties").
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	3,274
	Asset retirement obligations	(24		)
	Other liabilities	(20		)
	Total net assets	$	3,230
	Southern Dome Acquisition. In October 2013, the Partnership completed the acquisition of working interests in 25 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma (the "Southern Dome Acquisition") from Scintilla for total consideration of $14.5 million, net of purchase price adjustments.
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Consideration:
	Cash	$	4,260
	Fair value of common units granted (1)	8,608
	Contingent consideration (2)	1,600
	Total fair value of consideration	$	14,468
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	15,190
	Asset retirement obligations	(170		)
	Other liabilities	(552		)
	Total net assets	$	14,468
	_______________
	-1	The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).
	-2	The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideration.
	MCE Acquisition. In November 2013, the Partnership acquired 100% of the equity interests in MCE, other than Class B units that were retained by certain of the sellers as discussed further below (the "MCE Acquisition"). MidCentral Energy Services, LLC ("MCES"), a wholly owned subsidiary of MCE, operates an oilfield services business that offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region and in South Texas and West Texas, along with the rental of certain ancillary equipment necessary to perform such services.
	Total consideration for the MCE Acquisition is as follows (in thousands):
	Consideration:
	Cash	$	3,781
	Fair value of common units granted (1)	41,822
	Common units granted to MCE employees (2)	2,259
	Contingent consideration (3)	6,320
	MCE Class B units granted (4)	16,589
	Total fair value of consideration	$	70,771
	_______________
	-1	The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).
	-2	The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnership’s long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.
	-3	The owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCES for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $120.0 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCE Contingent Consideration.
	-4	Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See "Note 9 - Equity" for additional discussion of these incentive distributions. The Class B units were valued at $16.6 million through the use of a Monte Carlo simulation. Includes an adjustment of $2.6 million made during the fourth quarter of 2014 to the initial value of these units.
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
Cash	$	1,522
Accounts receivable	3,365
Other current assets	954
Property and equipment	7,923
Intangible asset (1)	36,772
Goodwill (2) (3) (4)	26,678
Other assets	19
Total assets acquired	77,233
Accounts payable and accrued liabilities (3)	(2,448		)
Factoring payable	(1,679		)
Long-term debt	(2,335		)
Total liabilities assumed	(6,462		)
Net assets acquired	$	70,771
_______________
-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 MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.
-3	Includes purchase price allocation adjustment of $0.1 million made during the third quarter of 2014 based on additional information received on accounts payable assumed.
-4	Includes purchase price allocation adjustment of $2.6 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.
Since the Chairman and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos, through his control over the Partnership’s general partner, controls the Partnership and also owned 36% of the equity interest in MCE, the MCE Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 36% equity interest in MCE acquired from Mr. Kos at his equity method carrying basis, which was $1.8 million as of November 12, 2013. The Partnership remeasured the 36% interest to determine the acquisition-date fair value and recognized a corresponding gain of $22.7 million on investment in acquired business.
The revenues and operating income included in the accompanying consolidated statements of operations for the year ended December 31, 2013 generated by the March 2013 Acquisition, the Southern Dome Acquisition, and the MCE Acquisition are shown in the table below. Operating income attributable to the March 2013 Acquisition and the Southern Dome Acquisition represents the excess of revenue over direct operating expenses and does 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. Direct operating expenses for the March 2013 Acquisition and the Southern Dome Acquisition include lease operating expenses and production taxes.
		Year Ended December 31, 2013
		(in thousands)
Revenue		$	11,465
Excess of revenues over direct operating expenses		$	6,533
Acquisition expense related to the acquisitions as of December 31, 2013 of approximately $2.1 million were included in general and administrative expenses in the accompanying consolidated statements of operations for the year ended December 31, 2013.
2014 Acquisitions
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 (the "CEU Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the CEU Contingent Consideration.
MCCS Acquisition. On June 26, 2014, we exercised the option granted in connection with the MCE Acquisition 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 3 - Contingent Consideration" for additional discussion of 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. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.
The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (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's business. Goodwill has been allocated to the oilfield services segment. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.
Since the Chairman and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos, through his control over the Partnership’s 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, which were issued and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition, are excluded from consideration based on the future service requirement for vesting. See "Note 9 - 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 ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million through the use of a probability analysis. See "Note 3 - Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. Includes a purchase price allocation adjustment made during the third quarter of 2014 for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.
The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):
Fair value of assets acquired and liabilities assumed:
Cash	$	1,668
Accounts receivable (1)	22,674
Other current assets (2)	620
Property and equipment (2)	43,853
Intangible assets (3)	68,700
Goodwill (4)	14,224
Total assets acquired	151,739
Accounts payable and accrued liabilities (1) (2)	(5,937		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,577		)
Net assets acquired	$	113,162
_______________
-1	Includes purchase price allocation adjustments resulting in an increase totaling $1.2 million during the fourth quarter, based on additional information received primarily on accounts receivable and accrued liabilities.
-2	Includes purchase price allocation adjustments resulting in an increase totaling $1.1 million during the third quarter of 2014, based on additional information received primarily on other current assets and property and equipment acquired.
-3	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.
-4	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. Purchase price allocation adjustments increased the amount assigned to goodwill by approximately $3.7 million in the third quarter of 2014, primarily as a result of an increase to the value of the contingent consideration based on additional information made available. Additional purchase price allocation adjustments in the fourth quarter of 2014 decreased the amount assigned to goodwill by approximately $1.2 million based on additional information received on accounts receivable and accrued liabilities.
Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the year ended December 31, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013. The pro forma combined results of operations for the year ended December 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 an 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.
	Year Ended December 31, 2014
	(in thousands, except per unit amounts)
Revenue	$	227,564
Net loss attributable to New Source Energy Partners L.P. (1)	$	(32,531	)
Net loss per common unit (1):
Basic	$	(1.61	)
Diluted	$	(1.61	)
_______________
-1	Excludes $24.3 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.
The amounts of revenues and operating loss included in the accompanying consolidated statements of operations for the year ended December 31, 2014 generated by the 2014 Material Acquisitions are shown in the table below. The operating income attributable to the CEU Acquisition represents the excess of revenue over direct operating expenses and does 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. Direct operating expenses include lease operating expenses and production taxes for the CEU Acquisition.
		Year Ended December 31, 2014
		(in thousands)
Revenue		$	69,167
Operating loss		$	(2,452	)
Acquisition expenses for the 2014 Material Acquisitions of $3.6 million were included in general and administrative expenses in the accompanying consolidated statements of operations for the year ended December 31, 2014.
The following unaudited pro forma combined results of operations are presented for the year ended December 31, 2013 as though the Partnership completed the March 2013 Acquisition, the Southern Dome Acquisition and the MCE Acquisition (collectively, the "2013 Material Acquisitions") as of January 1, 2012, which was the beginning of the earliest period presented at the time of the acquisition, and completed the 2014 Material Acquisitions as of January 1, 2013. The pro forma combined results of operations for the year ended December 31, 2013 have been prepared by adjusting the historical results of the Partnership to include the historical results of these acquisitions through the date of acquisition and estimates of the effect of the 2013 Material Acquisitions and the 2014 Material Acquisitions on the combined results. In addition, pro forma adjustments have been made for the interest that would have been incurred for financing the cash portion of the consideration of the 2013 Material Acquisitions with the Partnership's senior secured revolving credit facility and assume the units issued as consideration for the 2013 Material Acquisitions had been outstanding since January 1, 2012 and the units issued as consideration for the 2014 Material Acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund an acquisition, had been outstanding since January 1, 2013.
		Year Ended December 31, 2013
	(in thousands, except per unit amounts)
Revenue		$	188,232
Net loss attributable to New Source Energy Partners L.P. (1)		$	(15,931	)
Net loss per common unit (1):
Basic		$	(0.98	)
Diluted		$	(0.98	)
_______________
-1	Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the year ended December 31, 2013.

Contingent_Consideration

Contingent Consideration	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Contingent Consideration	Contingent Consideration
	The contingent consideration provided for in certain of our acquisitions represents additional consideration. The fair value of such contingent consideration is estimated using various inputs, including the probability that targets for additional payout will be met, as described below. As the significant inputs to determine fair value of the contingent consideration represent significant unobservable inputs, they are classified as Level 3 under the fair value hierarchy described in "Note 7 - Fair Value Measurements."
	A reconciliation of the beginning and ending balances of acquisition-related contingent consideration for the years ended December 31, 2014 and 2013 is as follows (in thousands):
		Year Ended December 31,
		2014			2013
	Contingent consideration, beginning balance	$	6,320		$	—
	Acquisition date fair value of contingent consideration - Southern Dome	—			1,600
	Acquisition date fair value of contingent consideration - MCE Acquisition	—			6,320
	Acquisition date fair value of contingent consideration - CEU Acquisition	—			—
	Acquisition date fair value of contingent consideration - MCCS Acquisition	4,057			—
	Acquisition date fair value of contingent consideration - Services Acquisition	21,984			—
	Change in fair value of contingent consideration	(9,031		)	(1,600		)
	Settlement of contingent consideration	—			—
	Contingent consideration, ending balance	23,330			6,320
	Less: current portion of contingent consideration	11,572			—
	Less: offsetting receivable due from former owners	957			—
	Contingent consideration, long-term	$	10,801		$	6,320
	Southern Dome Contingent Consideration. In conjunction with the Southern Dome Acquisition, the Partnership agreed to provide additional consideration to Scintilla if the average daily production attributable to the acquired properties for the nine months ended September 30, 2014 exceeded 383.5 Boe. The contingent consideration was determined to have a fair value of $1.6 million at the acquisition date and was included in the consideration for the Southern Dome Acquisition. The Partnership estimated the fair value as of December 31, 2013 at $0. As detailed in the acquisition agreement, the additional consideration was calculated as the value of average daily production for the nine months ended September 30, 2014 less (i) the asset value, (ii) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (iii) revenue attributable to any wells located in a specified project area that were not producing in paying quantities as of the effective date of the acquisition. Any change to the fair value of the contingent consideration was adjusted through earnings due to the factors impacting the ultimate payout. Based on actual production levels for the nine months ended September 30, 2014, no additional consideration is due to Scintilla.
	MCE Contingent Consideration. The former owners of MCE are 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, which is 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. The Partnership estimated fair value of the MCE Contingent Consideration was approximately $6.3 million at December 31, 2013, which is presented as contingent consideration payable in the accompanying consolidated balance sheets. Any change to the fair value of the contingent consideration is adjusted through earnings. Based on current projections for MCE, the MCE Contingent Consideration was deemed to have no value as of December 31, 2014. The decrease in fair value of $6.3 million is included in the accompanying consolidated statements of operations for the year ended December 31, 2014.
	CEU Contingent Consideration. In conjunction with the CEU Acquisition, the Partnership agreed to provide additional consideration to CEU if the average daily production attributable to the acquired working interest for the nine months ended September 30, 2014 exceeded 566.0 Boe. The CEU Contingent Consideration was determined to have no value at the acquisition date. As detailed in the acquisition agreement, the additional consideration was calculated as the acquisition value of the production increase less (i) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells located in a specified project area that were not producing in paying quantities as of the effective date of the acquisition. Based on actual production levels for the nine months ended September 30, 2014, no additional consideration is due to CEU.
	MCCS Contingent Consideration. The former 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, 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. Any changes to the fair value of the contingent consideration will be adjusted through earnings. Based on current projections for MCCS, the MCCS Contingent Consideration was deemed to have no value as of December 31, 2014. The decrease in fair value of $4.1 million is included in the accompanying consolidated statements of operations for the year ended December 31, 2014.
	EFS/RPS Contingent Consideration. 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 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 contingent consideration was $23.3 million as of December 31, 2014. The increase in fair value of approximately $1.3 million was adjusted through earnings and is included in the accompanying consolidated statements of operations for the year ended 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 contingent consideration to be extended to May 2016. As a result, this portion of the contingent consideration has been reflected as long-term in the accompanying consolidated balance sheet as of December 31, 2014. Additionally, a receivable of approximately $1.0 million due from the former owners has been offset against the contingent consideration obligation.

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	Debt
	The Partnership's debt consists of the following (in thousands):
		31-Dec-14			31-Dec-13
	Credit facility	$	83,000		$	78,500
	Notes payable	20,424			2,233
	Line of credit	3,619			—
	Total debt	107,043			80,733
	Less: current maturities of long-term debt	11,825			719
	Long-term debt	$	95,218		$	80,014
	Senior Secured Revolving Credit Facility
	The Partnership has a senior secured revolving credit facility that is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below, (the "credit facility"). As of December 31, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The 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 all 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 December 31, 2014, the Partnership was in compliance with all covenants under the credit facility.
	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 December 31, 2014 and December 31, 2013, the average annual interest rate on borrowings outstanding under the credit facility was 3.44% and 3.25%, respectively.
	Borrowings under the credit facility are limited to a borrowing base, the amount of which is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. The borrowing base is subject to a semi-annual redetermination. The borrowing base was lowered in November 2014 to $90.0 million from $102.5 million. As of December 31, 2014, we had $83.0 million in outstanding borrowings with $7.0 million of available borrowing capacity and no available borrowing capacity before restriction on distribution occurs. In January and February 2015, the Partnership repaid $2.0 million in outstanding borrowings under the credit facility, which resulted in $81.0 million outstanding with no restrictions on our ability to pay distributions in February 2015. Based on our reserve estimates and using forward commodity prices, we anticipate a reduction to our borrowing base on our credit facility at the redetermination in April 2015. The precise amount of the reduction is not known at this time but the decrease could range from approximately $20 million to $30 million. Under the credit agreement, we would have approximately three months from the date of notification of a borrowing base reduction to pay any amounts outstanding in excess of the new borrowing base. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with our current ratio covenant in certain future periods. We expect to successfully execute certain contemplated financing options to enable us to reduce the credit facility borrowings and comply with this covenant during 2015.
	Notes Payable
	The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. These notes range from 12-60 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 $7.6 million outstanding under the MCES notes payable as of December 31, 2014.
	In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on term loans held by EFS. These term loans had a balance of $12.9 million as of December 31, 2014 and mature on June 26, 2015. The term loans have a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at December 31, 2014, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The term loans are collateralized by various assets of the parties to the agreement and guaranteed by MCE and former owners of EFS and RPS. The Partnership is required to maintain a reserve bank account into which the lesser of $0.3 million or 100% of excess cash flow (as defined in the loan agreement) shall be deposited quarterly and used to fund an additional annual payment on September 30th of each year during the term of the loans.
	The EFS term 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; make loans to the Partnership; and dispose of assets. Additionally, beginning October 1, 2014, 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 $4.0 million, in each case as more fully described in the loan agreement. As of December 31, 2014, EFS and RPS were in compliance with the covenants under the term loan agreement.
	On March 13, 2015, we refinanced the EFS term loans to extend the maturity date from June 26, 2015 to March 13, 2018, which reduced the monthly payment, the reserve account requirement and the minimum working capital and cash balance covenant requirements. All other covenants and restrictions remain the same. As a result of this extension, the portion of principal now due January 1, 2016 or after of $8.3 million was classified on the accompanying consolidated balance sheet as long-term debt.
	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 on the line of credit which was originally set to mature in February 2015, but was extended to mature in May 2015. The line of credit replaced MCES' factoring payable agreement described in "Note 5 - Factoring Payable." Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at December 31, 2014. The line of credit is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. Based on the outstanding balance of $3.6 million, there was $0.4 million of available borrowing capacity at December 31, 2014.
	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 December 31, 2014, MCES was in compliance with this covenant under the line of credit.
	Debt Maturity
	The following is a schedule by years of minimum principal payments for debt as of December 31, 2014 (in thousands):
	Year ended December 31,		Amount (1)
	2015		$	11,825
	2016		7,185
	2017 (2)		87,809
	2018		219
	2019		5
	Total		$	107,043
	_______________
	-1	Reflects refinancing of term loan agreement in March 2015.
	-2	Includes credit facility borrowings of $83.0 million maturing in February 2017.

Factoring_Payable

Factoring Payable	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Factoring Payable	Factoring Payable
	The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of MCES. At December 31, 2013, the outstanding balance was $1.9 million. The outstanding balance was paid and the agreement was terminated in February 2014 when MCES established its line of credit. See "Note 4 - 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 $13.2 million as of December 31, 2014.

Derivative_Contracts

Derivative Contracts	12 Months Ended
	Dec. 31, 2014
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 to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations for a portion of its oil, natural gas and NGL production. While the use of derivative contracts limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and NGL, 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 December 31, 2014, 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 put option 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 December 31, 2014:
	Oil collars		Volumes		Floor Price				Ceiling Price
			(Bbls)
	2015		42,649		$	80			$	93.25
	Oil collars - three way		Volumes		Sold Put				Purchased Put			Ceiling Price
			(Bbls)
	2015		36,500		$	77.5			$	92.5		$	102.6
	Natural gas collars		Volumes		Floor Price				Ceiling Price
			(MMBtu)
	2015		1,362,382		$	4			$	4.32
	Natural gas put options		Volumes		Floor Price
			(MMBtu)
	2015		798,853		$	3.5
	2016		930,468		$	3.5
	Oil fixed price swaps		Volumes (Bbls)		Weighted Average Fixed Price
	2015		39,411		$	88.9
	2016		36,658		$	86
	Natural gas fixed price swaps		Volumes		Weighted Average Fixed Price
			(MMBtu)
	2015		800,573		$	4.25
	2016		629,301		$	4.37
	NGL fixed price swaps		Volumes		Weighted Average Fixed Price
			(Bbls)
	2015		84,793		$	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, the effects of netting assets and liabilities for which the right of offset exists (in thousands):
	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	)		$	—
	31-Dec-13		Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset				Net Amounts Presented
	Assets:
	Commodity derivatives - current assets		$	1,342		$	(1,212	)		$	130
	Commodity derivatives - long-term assets		1,638			(978		)		660
	Total		$	2,980		$	(2,190	)		$	790
	Liabilities:
	Commodity derivatives - current liabilities		$	4,379		$	(1,212	)		$	3,167
	Commodity derivatives - long-term liabilities		1,015			(978		)		37
	Total		$	5,394		$	(2,190	)		$	3,204
	See "Note 7 - 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 consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2014			2013				2012
	Total gain (loss) on derivative contracts, net (1)	$	10,707		$	(5,548	)		$	7,057
	_______________
	-1	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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. Beginning in the second quarter of 2014, 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, natural gas, and NGL 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, relying in part upon 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 December 31, 2013 and 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 3 - Contingent Consideration," the Partnership has agreed to pay additional consideration on the MCE Acquisition, the MCCS Acquisition and the Services Acquisition. 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-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	)
	31-Dec-13		Fair Value Measurements
	Description		Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
	Oil collars		$	—		$	(57	)	$	—		$	(57	)
	Natural gas collars		—			—			(9		)	(9		)
	Oil put options		—			28			—			28
	Natural gas and NGL put options		—			—			403			403
	Oil and natural gas fixed price swaps		—			132			—			132
	NGL fixed price swaps		—			—			(2,911		)	(2,911		)
	Contingent consideration		—			—			(6,320		)	(6,320		)
	Total		$	—		$	103		$	(8,837	)	$	(8,734	)
	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 years ended December 31, 2014, 2013 and 2012 (in thousands):
			Year Ended December 31,
			2014			2013			2012
	Beginning balance		$	(2,517	)	$	(112	)	$	(1,198	)
	(Loss) gain on derivative contracts		(2,432		)	(4,075		)	7,051
	Transfers out (1)		2,843			—			—
	Cash paid upon settlement		2,106			1,670			(5,965		)
	Ending balance		$	—		$	(2,517	)	$	(112	)
	Unrealized losses included in earnings relating to derivatives held at period end		$	—		$	(2,446	)	$	(112	)
	_______________
	-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. During the year ended December 31, 2013, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.
	See "Note 6 - Derivative Contracts" for additional discussion of our derivative contracts. See "Note 3 - Contingent Consideration" for a reconciliation of activity for contingent consideration during the years ended December 31, 2014 and 2013.
	Fair Value of Financial Instruments
	Credit Facility. The carrying amount of the credit facility of $83.0 million and $78.5 million as of December 31, 2014 and December 31, 2013, 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 $20.4 million and $2.2 million at December 31, 2014 and December 31, 2013 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 and impairments of goodwill and intangible assets. See "Note 2 - Acquisitions" and "Note 8 - Goodwill and Intangible Assets" for discussion of these valuations.

Goodwill_and_Intangible_Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Goodwill and Intangible Assets
	Goodwill
	Goodwill represents the estimated future economic benefits arising from other assets acquired in business combinations that could not be individually identified and separately recognized. See "Note 2 - Acquisitions" for discussion of our business acquisitions. Goodwill has been allocated to reporting units within the oilfield services segment and is not deductible for tax purposes. In connection with the MCE Acquisition in November 2013, the Partnership recorded $24.0 million of goodwill, which represents the balance at December 31, 2013. A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2013 to December 31, 2014 is as follows (in thousands):
	Goodwill at December 31, 2013	$	23,974
	Additions:
	MCCS Acquisition	4,060
	Services Acquisition	11,664
	Change due to purchase price allocation adjustments (1)	4,585
	Impairment	(34,968		)
	Goodwill at December 31, 2014	$	9,315
	_______________
	-1	Includes adjustments totaling $3.8 million during the third quarter of 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. Includes adjustments totaling $1.7 million during the fourth quarter of 2014 as a result of purchase price allocation adjustments of $2.6 million, $(0.7) million and $(0.2) million on the MCE Acquisition, MCCS Acquisition and Services Acquisition, respectively. See "Note 2 - Acquisitions" for discussion of the purchase price allocation adjustments.
	In the fourth quarter of 2014, the Partnership deemed the significant decline in commodity prices and the related impact or estimated impact to our oilfield services business to be a triggering event for the purpose of evaluating goodwill. As such, impairment tests were performed as of December 31, 2014. Primarily as a result of a decrease in projected revenue of the respective reporting units, which is a significant component in determining the fair value of the reporting units, the carrying value of all reporting units exceeded their fair value. We performed step two of the impairment test to determine the amount of goodwill that was impaired. The excess of the carrying amount of the reporting units' goodwill over the implied fair value of the goodwill, approximately $35.0 million, was recorded as impairment and included in the accompanying consolidated statements of operations for the year ended December 31, 2014.
	In order to estimate the fair value of the oilfield services reporting units (which is consistent with the entities acquired), we used the cost approach to value MCE and MCCS and a combination of the income approach and the market approach to value EFS and RPS. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a standalone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Partnership’s total capitalization. These fair value estimates were then compared to the carrying value of the reporting units. The fair values of MCES and MCCS exceeded their carrying values such that after computing the implied fair value of each reporting unit's goodwill, the goodwill was fully impaired. The implied fair values of EFS and RPS resulted in a partial impairment of each reporting unit's goodwill. A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events.
	Intangible Assets
	Intangible assets were identified in certain of the acquisitions during 2013 and 2014. See "Note 2 - Acquisitions" for discussion of our business acquisitions. Intangible assets are amortized over the expected cash flow period for customer relationships and over the agreement period, or three years, for the non-compete agreements. Amortization expense for the years ended December 31, 2014 and 2013 was $25.0 million and $1.8 million, respectively. There was no amortization expense for the year ended December 31, 2012.
	The Partnership's intangible assets at December 31, 2014 and December 31, 2013 consist of the following (in thousands):
		31-Dec-14			31-Dec-13
	Customer relationships - MCE Acquisition	$	36,772		$	36,772
	Customer relationships - Services Acquisition	64,200			—
	Non-compete agreements - Services Acquisition	4,500			—
	Customer relationships - MCCS Acquisition	1,700			—
	Total intangible assets	107,172			36,772
	Less: accumulated amortization	26,764			1,763
	Impairment	24,031			—
	Intangible assets, net	$	56,377		$	35,009
	In the fourth quarter of 2014, the Partnership deemed the significant decline in commodity prices and the related impact or estimated impact to our oilfield services business to be a triggering event for the purpose of evaluating its intangible assets for impairment. Accordingly, impairment tests were performed by calculating the estimated future cash flows to be generated by the respective revenue generating asset groups. The undiscounted future cash flows were in excess of the respective revenue generating asset groups' carrying value for the intangible assets from the Services Acquisition; therefore, no impairment of these intangible assets was indicated as of December 31, 2014. For the customer relationships for MCE and MCCS, the undiscounted future cash flows were less than the respective revenue generating asset group's carrying value. Based on the discounted cash flows of the asset group, a full impairment of these intangible assets, or approximately $24.0 million, was recorded and is included in the accompanying consolidated statements of operations for the year ended December 31, 2014.
	The amortization of customer relationships reflects a pattern in which the economic benefits of the assets will be consumed or used up. Amortization was estimated by using an accelerated method over seven years similar to the expected cash flow pattern of the acquired customer relationships, estimated for each of the five succeeding years ending December 31, as follows (in thousands):
			Total
	2015		$	19,164
	2016		12,743
	2017		7,976
	2018		4,767
	2019		3,211
	Thereafter		4,766
			$	52,627

Equity

Equity	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Equity	Equity
	Units
	Initial Public Offering. In February 2013, the Partnership completed its Offering of 4,000,000 common units representing limited partner interests in the Partnership at a price to the public of $20.00 per common unit. In March 2013, 250,000 common units were issued from the partial exercise of the underwriters' overallotment option. Total proceeds from the Offering and exercise of the overallotment option, net of offering costs and underwriter discounts, were $76.6 million. In exchange for the contribution by NSEC of the IPO Properties and certain commodity derivative contracts, the Partnership distributed to NSEC $15.8 million and issued to NSEC 777,500 common units, 2,205,000 subordinated units, a $25.0 million note payable and approximately 50.0% of equity interests in our general partner, which owns all of the Partnership general partner units.
	Private Placement. In December 2013, we completed a private placement of 465,000 common units pursuant to a common unit purchase agreement, resulting in approximately $9.8 million in proceeds to us. The proceeds from this offering were used for general corporate purposes.
	Issuance for Acquisitions. In 2013, we issued 3,739,578 common units to satisfy the equity portion of the consideration paid in the March 2013 Acquisition, the Southern Dome Acquisition and the MCE Acquisition. 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, respectively. See "Note 2 - Acquisitions" for additional discussion of these transactions.
	Equity Offering. On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. 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.
	At the Market Offering. On October 3, 2014, the Partnership and our general partner entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (the “Sales Agent”). Pursuant to the terms of the EDA, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. Sales of such common units, if any, will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange ("NYSE") at market prices, or as otherwise agreed by the Partnership and the Sales Agent. On October 6, 2014, the Partnership sold 720,000 common units under the EDA for proceeds of approximately $16.2 million, net of offering costs, which included a commission to the Sales Agent of 1.75% on the principal amount of the offering. Proceeds were used to pay down a portion of the Partnership's outstanding debt and for general corporate purposes. No additional sales were made through December 31, 2014.
	Distributions
	The common units and the subordinated units are separate classes of limited partner interests. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement.
	Subordinated Units. As discussed above, all of the subordinated units are held by NSEC. The partnership agreement provides that, during the subordination period, common units have the right to receive distributions of Available Cash from Operating Surplus (each as defined in the partnership agreement) quarterly in an amount equal to $0.525 per unit (the “Minimum Quarterly Distribution”), plus any arrearages of the Minimum Quarterly Distribution on common units from prior quarters, before any distributions of Available Cash from Operating Surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units are not entitled to receive distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Additionally, beginning with the first quarter of 2013, if our average production declines below 3,200 Boe/d for any preceding four-quarter period, then the subordinated units will not be entitled to receive the quarterly distributions otherwise payable on the subordinated units for such quarter.
	The subordination period will end on the first business day after the Partnership has earned and paid at least (i) $2.10 (the Minimum Quarterly Distribution on an annualized basis) on each outstanding common unit, subordinated unit and general partner unit for each of twelve consecutive quarters ending on or after December 31, 2015 or (ii) $2.63 (125% of the annualized Minimum Quarterly Distribution) on each outstanding common unit, subordinated unit and general partner unit and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. During the subordination period, distributions pertaining to any quarter in which the subordinated units are not entitled to receive distributions due solely to the minimum annual production requirement shall be included for purposes of determining if requirements have otherwise been met for twelve consecutive quarters with respect to aggregate distributions equaling or exceeding the minimum quarterly distribution on all common, subordinated, general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units were earned in respect of such quarter.
	Based on the distributable cash flow attributable to the fourth quarter of 2014, the distribution per common unit declared and paid in February 2015 was $0.20. As this is below the Minimum Quarterly Distribution per the partnership agreement, the subordinated units did not receive distributions for this period. Additionally, the subordinated units are not entitled to receive distributions until the common units receive an amount equal to the Minimum Quarterly Distribution and all cumulative arrearages, or approximately $5.3 million.
	Incentive Distribution Rights. Our general partner currently holds incentive distribution rights (“IDRs”), which may be transferred separately from the general partner interest, subject to restrictions as discussed in the partnership agreement. The following table illustrates the allocations of available cash from operating surplus between unitholders and the general partner based on the specified target distribution levels.
		Total Quarterly				Marginal Percentage Interest in Distributions (1)
		Distributions per Unit				Unitholders		General Partner (2)
	Minimum Quarterly Distribution	$0.53				99%		1%
	First Target Distribution	$0.53	-	$0.60		99%		1%
	Second Target Distribution	$0.60	-	$0.66		86%		14%
	Thereafter	above		$0.66		76%		24%
	_______________
	(1) Represents the percentage interest in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
	(2) Includes the 1% general partner interest as of December 31, 2014 and assumes contribution of any additional capital necessary to maintain the current general partner interest, retention of IDRs by the general partner and no arrearages on common units.
	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 years ended December 31, 2014 and 2013, are shown in the following table (in thousands, except per unit amounts):
	Distributions		Payable Date		Distribution per Unit				Common Units		Subordinated Units		General Partner Units		Total
	2014
	First Quarter		15-May-14		$	0.58			$	7,852	$	1,279	$	90	$	9,221
	Second Quarter		15-Aug-14		$	0.585			$	9,025	$	1,290	$	91	$	10,406
	Third Quarter		14-Nov-14		$	0.585			$	9,454	$	1,290	$	91	$	10,835
	Fourth Quarter (3)		13-Feb-15		$	0.2			$	3,281	$	—	$	31	$	3,312
	2013
	First Quarter (1)		15-May-13		$	0.274			$	1,857	$	605	$	43	$	2,505
	Second Quarter		15-Aug-13		$	0.55			$	3,725	$	1,213	$	85	$	5,023
	Third Quarter		15-Nov-13		$	0.575			$	3,895	$	1,268	$	89	$	5,252
	Fourth Quarter (2)		14-Feb-14		$	0.575			$	4,681	$	1,268	$	89	$	6,038
	_______________
	-1	Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit.
	-2	Distributions were not paid on the 1,947,033 common units issued in conjunction with the MCE Acquisition pursuant to an arrangement with the sellers to forgo their rights to distributions for the fourth quarter of 2013 on these units.
	-3	Because the declared common unit distribution is below the Partnership’s Minimum Quarterly Distribution of $0.525 per unit, the Partnership’s subordinated units were not entitled to receive distributions. Under the terms of the partnership agreement, the subordinated units are entitled to distributions once the common unit distribution meets or exceeds the Minimum Quarterly Distribution and all common unit arrearages have been satisfied.
	As discussed above under "Incentive Distribution Rights" and 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 2014 and 2013 did not exceed the specified targets.
	See "Note 17 - Subsequent Events" for discussion of distribution declared in January 2015.
	Noncontrolling Interest
	As part of the MCE Acquisition, certain former owners of MCE retained 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 MCE. Generally, the specified target distribution levels for the allocations of MCE's available cash from operating surplus between the Partnership and the Class B unitholders are adjusted for any capital contribution made by the Partnership to MCE as provided for in the MCE partnership agreement. (However, in the case of the contribution of the businesses acquired in the Services Acquisition the target distributions levels were not adjusted. Instead, the MCE partnership agreement was amended to provide that the Class B units will not participate in distributions of available cash provided by the operations of EFS and RPS.) Specifically, the target distributions are proportionally adjusted by 3.75% of an additional contribution of cash, cash equivalents or the value of contributed property, as further discussed in the partnership agreement. At any time after the Partnership has made four consecutive distributions to the Class B unitholders, the Class B unitholders have the right to reset, at higher levels, the minimum target distributions. As these Class B Units are not held by the Partnership, they are presented as noncontrolling interest in the accompanying 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.
	The following table illustrates the allocations of MCE's available cash from operating surplus between the Partnership and the Class B unitholders based on the specified target distribution levels. 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 Partnership 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 of December 31, 2014, 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%
	Based on MCE's distribution amounts, the MCE Class B unitholders were entitled to distributions of approximately $0.2 million for the third quarter of 2014. No distributions were due to the MCE Class B unitholders for the first, second or fourth quarters of 2014.
	Equity Compensation
	On August 18, 2011, NSEC granted 2,900,000 shares of restricted common stock with 1,000,000 shares vesting upon the first anniversary of the date of grant, 700,000 shares vesting on the second anniversary of the date of grant, and the remaining 1,200,000 shares vesting on the completion of the initial public offering of NSEC's common stock pursuant to a filed prospectus provided that the employees remain employed by NSEC on the applicable vesting dates subject to limited exceptions.
	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"). Such awards are valued based upon the market value of common units on the date of grant and expensed over the relevant vesting period to the extent the awards contain a service requirement. If there is no service requirement, the awards are expensed at the time of grant.
	On February 13, 2013, the Partnership granted 367,500 units of restricted common units to consultants, officers and other employees. Disposition of the units is restricted until the termination of the subordination period. The restricted units do not contain a future service requirement from the recipients. Accordingly, the Partnership recorded compensation expense of $7.4 million related to these awards as general and administrative expense in the accompanying consolidated statements of operations for the year ended December 31, 2013.
	On November 12, 2013, as part of the MCE Acquisition, the Partnership granted 99,768 restricted common units to employees of MCE. A portion of these, or 19,490 common units, had a one-year vesting period and were subject to vesting restrictions based on employment status. Equity-based compensation expense was recognized straight-line over the one-year vesting period for the fair value of these units and included in general and administrative expense in the accompanying consolidated statements of operations.
	For the year ended December 31, 2014 and 2013, the Partnership recorded equity-based compensation expense for restricted common units of $0.7 million and $7.5 million, respectively. Additionally, $8.2 million and $0.4 million, an allocated amount of NSEC stock-based compensation related to these awards, for the year ended December 31, 2012 and the period January 1, 2013 to February 13, 2013, was recognized as general and administrative expense in the accompanying consolidated statements of operations for the years ended December 31, 2012 and 2013, respectively.
	Unamortized equity-based compensation expense related to these awards was $0.2 million as of December 31, 2014 and will be recognized on a straight line basis over 1.2 years.
	Restricted equity, excluding phantom units, activity for the year ended December 31, 2014 and period from February 13, 2013 through December 31, 2013 was as follows:
		Number of Shares			Weighted-Average Grant Date Fair Value
	Granted	467,268			$	20.56
	Vested	—			$	—
	Unvested restricted units outstanding at December 31, 2013	467,268			$	20.56
	Granted	27,275			$	22.63
Vested	(45,985	)		$	(21.77	)
Forfeited/Canceled	(2,600	)		$	22.64
Unvested restricted units outstanding at December 31, 2014	445,958			$	20.51
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. If a phantom unit is forfeited, the associated common units are released from escrow to an entity owned by the former owners of EFS and RPS. Except as otherwise provided in the Phantom Unit Agreement, phantom units subject to forfeiture restrictions may be forfeited upon termination of employment prior to the end of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the holder until the phantom units vest, the recipients have distribution equivalent rights on these phantom units from the date of grant.
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 in conjunction with the Services Acquisition. As a result, the 401,171 phantom units with a service requirement valued at $10.1 million, 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. For the year ended December 31, 2014, the Partnership recorded equity-based compensation expense for phantom units of approximately $2.5 million. At December 31, 2014, approximately $7.6 million remains to be expensed on a straight line basis over 1.5 years. The associated common units held in escrow are reflected as contra equity on the accompanying consolidated balance sheet at December 31, 2014.

Earnings_per_Unit

Earnings per Unit	12 Months Ended
	Dec. 31, 2014
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 year ended December 31, 2014, LTIP awards of 5,349 common units were excluded in the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of December 31, 2013. Therefore, basic and diluted earnings per unit are the same for the year ended December 31, 2013.
	Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. The Partnership’s earnings per unit calculations, which allocate earnings to the general partner based on the general partner interest, reflect that, while such distribution to the general partner with respect to its general partner interest was made, no incentive distributions were permitted or made to the general partner because quarterly distributions declared by the board of directors for 2013 and 2014 periods did not exceed the specified targets.
	Basic and diluted earnings per unit for the year ended December 31, 2014 and the period February 13, 2013 through December 31, 2013 were computed as follows (in thousands, except per unit amounts):
		Year Ended									February 13, 2013 through
		December 31, 2014									December 31, 2013
		Common Units			Subordinated Units			General Partner			Common Units		Subordinated Units		General Partner
	Net (loss) income	$	(35,652	)	$	(6,256	)	$	(409	)	$	16,929	$	4,099	$	291
	Weighted average units outstanding	13,517			2,205			155			6,995		2,205		155
	Basic and diluted (loss) income per unit	$	(2.64	)	$	(2.84	)	$	(2.64	)	$	2.42	$	1.86	$	1.88

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions
	Ownership. The Partnership is controlled by the Partnership's general partner, which is 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 5.3% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through Deylau, LLC, an entity he controls. As of December 31, 2014, 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 5.6% of our general partner and 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.
	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. New Dominion has historically performed this service for NSEC. 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 reimbursed 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 $0.4 million as of both December 31, 2014 and December 31, 2013, all of which is classified as a long-term liability in the accompanying 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 years ended December 31, 2014, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2014		2013		2012
	Producing overhead and supervision charges	$	2,905	$	1,636	$	599
	Drilling and completion supervision charges	368		520		27
	Saltwater disposal fees	1,235		696		1,642
	Total expenses incurred	$	4,508	$	2,852	$	2,268
	At December 31, 2014 and December 31, 2013, $1.9 million and $1.3 million, respectively, were due to New Dominion for charges and fees under operating agreements and included in accounts payable - related party in the accompanying consolidated balance sheets. See "Note 15 - Commitments and Contingencies" for discussion of litigation with New Dominion.
	NSEC. Under an agreement by and among NSEC, the Partnership and our general partner, NSEC provided administrative services for the Partnership from February 13, 2013 through December 31, 2013. For the year ended December 31, 2013, fees paid for such services were $2.4 million and were included in general and administrative expenses in the accompanying consolidated statements of operations.
	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 year ended December 31, 2014, the amount paid to our general partner for such reimbursements was $3.9 million and was included in general and administrative expenses in the accompanying consolidated statements of operations. Additionally, we received and re paid approximately $1.5 million to our general partner during the year ended December 31, 2014 for operational cash advances. At December 31, 2014, $2.3 million was due to our general partner for reimbursement and included in accounts payable - related party in the accompanying consolidated balance sheet.
	Acquisitions. As described in "Note 2 - Acquisitions," we acquired oil and natural gas properties, MCE and MCCS from related parties. As these acquisitions were with related parties, the transactions were subject to approval by the board of directors of the Partnership's general partner, based on the approval and recommendation of its conflicts committee.
	As discussed in "Note 2 - Acquisitions," Mr. Kos was a 36% owner of MCE prior to the MCE Acquisition. Additionally, Dikran Tourian, the President and Chief Operating Officer of our general partner and member of our general partner's board of directors, was a 36% owner of MCE prior to the MCE Acquisition. In conjunction with the MCE Acquisition, Mr. Kos and Mr. Tourian retained Class B units that are entitled to incentive distributions as discussed in "Note 9 - Equity" as well as contingent consideration as discussed in "Note 3 - Contingent Consideration." In the third quarter of 2014, the Class B unit distribution targets were met.
	On June 26, 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 3 Contingent Consideration" 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. As of December 31, 2014, the payable of $0.7 million had been paid.
	See "Note 17 - Subsequent Events" for discussion of land acquired we acquired from Mr. Kos and Mr. Tourian in 2015.
	Transactions with Chief Financial Officer. The Partnership engaged Finley & Cook, PLLC ("Finley & Cook") to provide various accounting services on our behalf during the years ended December 31, 2014 and 2013. Richard Finley, the Chief Financial Officer of our general partner, was an equity member of Finley & Cook, holding a 31.5% ownership interest until October 2014. The Partnership paid Finley & Cook approximately $0.4 million in fees for the year ended December 31, 2014. NSEC engaged Finley & Cook to provide various accounting services on our behalf during the year ended December 31, 2013. Fees for such accounting services were included in the amounts paid to NSEC, as discussed above.

Property_Plant_and_Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2014
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, natural gas, and NGL 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.
	The Partnership does not have any costs associated with its oil and natural gas properties that are excluded from amortization. The average rates used for depletion of oil and natural gas properties were $14.92 per Boe in 2014, $12.42 per Boe in 2013 and $12.51 per Boe in 2012.
	Property and equipment, net. Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):
		31-Dec-14			31-Dec-13
	Vehicles and transportation equipment	$	15,891		$	561
	Machinery and equipment	44,441			4,757
	Office furniture and equipment	1,069			79
	Iron	12,258			2,971
	Total	73,659			8,368
	Less: accumulated depreciation	(4,773		)	(202		)
	Property and equipment, net	$	68,886		$	8,166

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
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 years ended December 31, 2014, 2013 and 2012 is as follows (in thousands):
		2014			2013		2012
	Asset retirement obligations at January 1	$	3,455		$	1,510	$	1,411
	Liability incurred upon acquiring and drilling wells	249			1,585		34
	Revisions	(238		)	151		(51		)
	Liability settled or disposed	(112		)	—		—
	Accretion	327			209		116
	Asset retirement obligations at December 31	3,681			3,455		1,510
	Less: current portion	113			—		—
	Asset retirement obligations, net of current	$	3,568		$	3,455	$	1,510

Accounts_Payable_and_Accrued_L

Accounts Payable and Accrued Liabilities	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Accounts Payable and Accrued Liabilities	Accounts Payable and Accrued Liabilities
	Accounts payable and accrued expenses consist of the following (in thousands):
		December 31,
		2014		2013
	Accounts payable trade	$	9,028	$	1,922
	Accounts payable - other	3,754		318
	Accrued wages and benefits	1,689		338
	Accrued franchise and sales taxes	301		385
	Accrued interest	188		304
	Other	366		—
	Total accounts payable and accrued expenses	$	15,326	$	3,267

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Commitments
	The Partnership is a party to various agreements under which it has rights and obligations to participate in the acquisition and development of undeveloped properties held and to be acquired by Scintilla and New Dominion. These properties will be held by New Dominion for the benefit of the Partnership pending development of the properties. The Partnership is required by its underlying agreements with New Dominion to pay certain acreage fees to reimburse New Dominion for the cost of the acreage attributable to the Partnership’s working interest when invoiced by New Dominion. The Partnership recognizes an asset and corresponding liability as the acreage costs are incurred by New Dominion. See "Note 11 - 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.
	On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into a development agreement (the "Development Agreement") with NSEC and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, the Partnership has agreed to maintain an average annual maintenance drilling budget of at least $8.2 million to drill certain of the Partnership’s proved undeveloped locations and maintain the Partnership’s producing wells. As of December 31, 2014, we had incurred $23.1 million towards the annual maintenance drilling budget. Based on amounts incurred in 2013 and 2014, we have fulfilled our commitment for the maintenance drilling budget under the Development Agreement.
	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.
	See "Note 3 - Contingent Consideration" for discussion of contingencies related to certain acquisitions.
	Operating Lease Obligations
	We have obligations under noncancelable operating leases, primarily for office space and field locations. Total rental expense under operating leases for the years ended December 31, 2014 and 2013 was approximately $0.8 million and $0.1 million, respectively. The following is schedule by year of lease obligations and minimum lease payments for non-cancelable leases with a term of more than one year at December 31, 2014 (in thousands):
	Year
	2015	$	1,299
	2016	1,126
	2017	650
	2018	424
	2019	312
	Thereafter	520
	Total	$	4,331
	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. Subsequent to the filing by the defendants of their motions to dismiss, the parties agreed to a mediation to be held on March 24, 2015. The Partnership and the other defendants intend to defend this lawsuit vigorously and believe the plaintiffs' claims are without merit. 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 February and March 2015, New Dominion withheld revenue from the Partnership's sold oil and natural gas production in satisfaction of the claims. As with the proceeding described above, the Partnership intends to pursue this matter vigorously and believes the claims are without any substantial merit. This claim will be addressed at the March 24, 2015 mediation described above. 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	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information
	The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties 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 (1)			Total
	Year Ended December 31, 2014
	Revenues		$	61,488		$	104,155		$	165,643
	Direct operating expenses		21,450			60,904			82,354
	Segment margin		40,038			43,251			83,289
	General and administrative expenses		11,051			17,620			28,671
	Change in fair value of contingent consideration		(9,031		)	—			(9,031		)
	Impairment		—			59,000			59,000
	Depreciation, depletion, amortization and accretion		25,113			29,566			54,679
	Income (loss) from operations		$	12,905		$	(62,935	)	$	(50,030	)
	Interest expense		$	(3,726	)	$	(1,315	)	$	(5,041	)
	Gain on derivative contracts, net		$	10,707		$	—		$	10,707
	Gain on investment in acquired business		$	2,298		$	—		$	2,298
	Capital expenditures (2)		$	23,662		$	21,349		$	45,011
	At December 31, 2014
	Total assets		$	201,097		$	176,368		$	377,465
	Year Ended December 31, 2013
	Revenues		$	46,937		$	3,738		$	50,675
	Direct operating expenses		15,300			2,040			17,340
	Segment margin		31,637			1,698			33,335
	General and administrative expenses (3)		13,787			973			14,760
	Change in fair value of contingent consideration		(1,600		)	—			(1,600		)
	Depreciation, depletion, amortization and accretion		16,799			1,966			18,765
	Income (loss) from operations		$	2,651		$	(1,241	)	$	1,410
	Interest expense		$	(3,951	)	$	(127	)	$	(4,078	)
	Gain on derivative contracts, net		$	(5,548	)	$	—		$	(5,548	)
	Gain on investment in acquired business		$	22,709		$	—		$	22,709
	Capital expenditures (2)		$	48,319		$	445		$	48,764
	At December 31, 2013
	Total assets		$	181,440		$	73,270		$	254,710
	_______________
	-1	The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See "Note 2 - Acquisitions" for discussion.
	-2	On an accrual basis and exclusive of acquisitions.
	-3	Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.
	Major Customers. Historically, the majority of the Partnership's revenue has been from oil and natural gas properties in the Hunton formation in east-central Oklahoma. The addition of our oilfield services segment in November 2013 and the acquisition of three oilfield service companies in June 2014 expanded our customer base. The following table reflects purchases by customers exceeding 10% of our total sales for the years ended December 31:
	Purchaser		2014		2013	2012
	Scissortail		26%		80%	84%
	United Petroleum Purchasing		< 10%		14%	16%
	No one customer from our oilfield services business comprised more than 10% of our total sales for the years ended December 31, 2014 or 2013. The Partnership believes the loss of any one purchaser or customer would not have a material adverse effect on the ability of the Partnership to sell its production or services to a replacement purchaser.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events
	Distributions. On January 20, 2015, the Partnership declared quarterly distributions of $0.20 per unit to unitholders of record, including holders of common and general partner units for the fourth quarter of 2014. The following distributions were paid on February 13, 2015 to holders of record as of the close of business on February 2, 2015 (in thousands):
		Common Units		Subordinated Units		General Partner Units		Total
	Distributions	$	3,281	$	—	$	31	$	3,312
	Because the declared common unit distribution is below the Partnership’s Minimum Quarterly Distribution of $0.525 per unit, the Partnership’s subordinated units were not entitled to receive distributions. Under the terms of the partnership agreement, the subordinated units are entitled to distributions once the common unit distribution meets or exceeds the Minimum Quarterly Distribution and all common unit arrearages have been satisfied.
	Property Acquisition. On January 9, 2015, MCLP 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, Chief Executive Officer of our general partner, and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner, for approximately $0.9 million. Additionally, on February 24, 2015, MCLP acquired land located in Karnes County, Texas from an entity owned 50% by Mr. Kos and 50% 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 MCLP to Mr. Kos and Mr. Tourian.

Supplemental_Information_on_Oi

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)	Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)
	The supplemental information includes capitalized costs related to oil, natural gas, and NGL producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil, natural gas, and NGL producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows ("Standardized Measure") associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the Standardized Measure associated with proved oil, natural gas and NGL reserves.
	Capitalized Costs Related to Oil and Natural Gas Producing Activities
	The Partnership’s capitalized costs for oil, natural gas, and NGL activities consisted of the following (in thousands)
		December 31,
		2014				2013				2012
	Proved	$	332,413			291,829				$	202,795
	Less: accumulated depreciation, depletion and amortization	(153,734		)		(128,961		)		(112,372		)
	Net capitalized costs for oil and natural gas properties	$	178,679			$	162,868			$	90,423
	Costs Incurred in Oil and Natural Gas Property Acquisition and Development
	Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follow (in thousands):
		Year Ended December 31,
		2014				2013				2012
	Property acquisition costs	$	18,520			$	58,014			$	—
	Development costs	22,793				29,451				11,382
	Total costs incurred	$	41,313			$	87,465			$	11,382
	There were no exploration costs incurred in 2014, 2013 or 2012. Additionally, no internal costs or interest expense were capitalized in 2014, 2013 and 2012.
	Results of Operations for Oil, Natural Gas, and NGL Producing Activities
	The Partnership’s results of operations from oil, natural gas, and NGL producing activities for each of the years 2014, 2013 and 2012 are shown in the following table (in thousands):
		Year Ended December 31,
		2014				2013				2012
	Revenues	$	61,488			$	46,937			$	35,596
	Expenses
	Production	21,450				15,300				7,361
	Depreciation and depletion	24,786				16,590				14,409
	Accretion of asset retirement obligations	327				209				116
	Total expenses	46,563				32,099				21,886
	Results of operations for oil and natural gas producing activities	$	14,925			$	14,838			$	13,710
	Oil, Natural Gas and NGL Reserve Quantities
	Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.
	The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Partnership’s senior engineer and independent petroleum consultant relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Partnership’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:
	•	the quality and quantity of available data and the engineering and geological interpretation of that data;
	•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;
	•	the accuracy of mandated economic assumptions such as the future prices of oil, natural gas and NGLs; and
	•	the judgment of personnel preparing the estimates.
	Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.
	Oil, natural gas, and natural gas liquid reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
	Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates are inherently imprecise and the estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
	The Partnership's properties are all located in the United States, exclusively in the Hunton formation in east-central Oklahoma. The estimates of proved reserves associated with the Partnership properties at December 31, 2014, 2013 and 2012 are based on reports prepared by independent reserve engineers Ralph E. Davis Associates, Inc. Proved reserves for all periods presented were estimated in accordance with the guidelines established by the Securities and Exchange Commission and the FASB.
	The pricing used for estimates of reserves as of December 31, 2014, 2013 and 2012, was based on an unweighted twelve-month average WTI posted price of $94.99, $96.78, and $94.71, respectively, per Bbl for oil and a Henry Hub spot natural gas price of $4.35, $3.67, and $2.76, respectively, per Mcf for natural gas. NGLs were priced at 38%, 38%, and 36% of the oil prices for the periods ended December 31, 2014, 2013 and 2012, respectively, which approximates the realizable value received.
	The following table summarizes the prices utilized in the reserve estimates as adjusted for location, grade and quality as of December 31:
		Year Ended December 31,
		2014				2013				2012
	Oil	$	91.98			$	93.71			$	92.74
	Natural gas	$	4.13			$	3.55			$	2.59
	NGL	$	34.95			$	35.61			$	33.39
	The following table provides a rollforward of the total net proved reserves for the years ended December 31, 2012, 2013 and 2014, as well as proved developed and proved undeveloped reserves at the end of each respective year. Oil and NGL volumes are expressed in Bbls and natural gas volumes are expressed in Mcf.
		Oil			Natural Gas			NGL			Total
		(Bbls)			(Mcf)			(Bbls)			(Boe)
	Total proved reserves
	Balance, January 1, 2012	953,430			21,605,810			9,307,940			13,862,339
	Revisions	(469,630	)		1,295,502			57,825			(195,888	)
	Purchases of reserves	—			—			—			—
	Extensions and discoveries (1)	106,400			3,512,130			1,049,350			1,741,105
	Production	(61,010	)		(2,278,342	)		(711,195	)		(1,151,929	)
	Balance, December 31, 2012	529,190			24,135,100			9,703,920			14,255,627
	Proved developed reserves	249,140			11,980,390			6,182,620			8,428,492
	Proved undeveloped reserves	280,050			12,154,710			3,521,300			5,827,135
	Total proved reserves	529,190			24,135,100			9,703,920			14,255,627
	Balance, January 1, 2013	529,190			24,135,100			9,703,920			14,255,627
	Revisions	(49,507	)		1,897,316			(857,896	)		(591,184	)
	Purchases of reserves	1,031,040			11,889,850			4,727,060			7,739,742
	Extensions and discoveries (1)	13,130			1,092,500			374,390			569,603
	Production	(84,273	)		(2,764,336	)		(790,234	)		(1,335,230	)
Balance, December 31, 2013	1,439,580			36,250,430			13,157,240			20,638,558
Proved developed reserves	922,190			19,625,190			8,290,570			12,483,625
Proved undeveloped reserves	517,390			16,625,240			4,866,670			8,154,933
Total proved reserves	1,439,580			36,250,430			13,157,240			20,638,558
Balance, January 1, 2014	1,439,580			36,250,430			13,157,240			20,638,558
Revisions (2)	(404,382	)		(7,304,864	)		(3,889,584	)		(5,511,443	)
Purchases of reserves	717,480			5,370,830			247,540			1,860,158
Extensions and discoveries (3)	60,840			1,849,500			621,580			990,670
Production	(163,338	)		(3,673,836	)		(885,117	)		(1,660,761	)
Balance, December 31, 2014	1,650,180			32,492,060			9,251,659			16,317,182
Proved developed reserves	1,516,850			25,898,620			7,706,900			13,540,186
Proved undeveloped reserves	133,330			6,593,440			1,544,759			2,776,996
Total proved reserves	1,650,180			32,492,060			9,251,659			16,317,182
_______________
-1	Extensions and discoveries are due to development drilling in the Golden Lane area.
-2	Revisions are primarily attributable to the reclassification of certain proved undeveloped reserves to probable reserves because our expected drilling plan has been curtailed as a result of low commodity prices and rising costs to drill wells.
-3	Extensions and discoveries are due to wells drilled in the Golden Lane field in 2014.
Standardized Measure of Discounted Future Net Cash Flows
The Standardized Measure is computed by applying the twelve-month unweighted average of the first-day-of-the-month pricing for oil, natural gas and NGL to the estimated future production of proved oil, natural gas and NGL reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.
Discounted future cash flow estimates like those shown herein are not intended to represent estimates of the fair value of the Partnership’s oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil, natural gas and NGL prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
The following table provides the Standardized Measure as of the periods presented below (in thousands):
	2014				2013				2012
Future production revenues	$	609,362			$	732,340			$	435,670
Future costs:
Production	(220,350		)		(223,582		)		(121,541		)
Development	(48,216		)		(110,881		)		(52,032		)
Income tax expense(1)	—				—				(85,090		)
10% annual discount for estimated timing of cash flows	(161,536		)		(185,152		)		(82,746		)
Standardized measure of discounted net cash flows	$	179,260			$	212,725			$	94,261
_______________
-1	Our Standardized Measure as of December 31, 2012 includes effects of income taxes. The Partnership was not a taxable entity in 2013 or 2014.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table provides a rollforward of the Standardized Measure for the years ended December 31, (in thousands):
	2014				2013				2012
Discounted future net cash flows at beginning of year	$	212,725			$	94,261			$	153,333
Increase (decrease)
Sales and transfers, net of production costs	(40,321		)		(31,637		)		(28,235		)
Net changes in prices and production costs	2,109				3,952				(93,618		)
Extensions and discoveries	18,482				25,280				8,688
Changes in future development costs	9,886				(61,939		)		8,350
Previous development costs incurred	23,076				29,451				11,382
Acquisition of reserves in place	29,955				76,596				—
Revisions of previous quantity estimates	(72,636		)		(7,035		)		(5,833		)
Changes in income taxes	—				47,387				33,532
Timing and other	(25,289		)		26,983				(8,671		)
Accretion of discount	21,273				9,426				15,333
Net increase (decrease)	(33,465		)		118,464				(59,072		)
Discounted future net cash flows at end of year	$	179,260			$	212,725			$	94,261

Quarterly_Results_of_Operation

Quarterly Results of Operations	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Results of Operations (unaudited)	Quarterly Results of Operations (unaudited)
	The following transactions are reflected in the quarterly results below:
	•	oil and natural gas properties located in the Golden Lane and Luther fields in Oklahoma in March 2013;
	•	oil and natural gas properties located in the Southern Dome field in Oklahoma in May 2013;
	•	oil and natural gas properties located in the Golden Lane field in Oklahoma in July 2013;
	•	working interests and related undeveloped leasehold rights located in the Southern Dome field in Oklahoma in October 2013 and January 2014;
	•	MCE Entities, oilfield services companies, in November 2013; and
	•	MCCS, EFS and RPS, oilfield services companies, in June 2014.
	The following table summarizes quarterly financial data for the years ended December 31, 2014 and 2013 (in thousands, except per unit data):
			Quarter Ended
	2014		31-Mar			30-Jun		30-Sep			31-Dec
	Revenues		$	27,427		$	26,818	$	56,424		$	54,974
	Income (loss) from operations (1) (2) (3)		2,572			1,690		(5,075		)	(49,217		)
	Income tax expense		—			—		—			—
	Net (loss) income (1) (2) (3)		$	(1,531	)	$	1,586	$	(2,754	)	$	(39,376	)
	(Loss) earnings per common unit
	Basic		$	(0.12	)	$	0.11	$	(0.17	)	$	(2.11	)
	Diluted		$	(0.12	)	$	0.11	$	(0.17	)	$	(2.11	)
	2013
	Revenues		$	9,360		$	10,649	$	12,431		$	18,235
	(Loss) income from operations (4)		(6,118		)	2,456		2,121			2,951
	Income tax benefit		12,126			—		—			—
	Net (loss) income (4)		$	(1,397	)	$	8,151	$	(1,986	)	$	21,854
	(Loss) earnings per common unit (5)
	Basic		$	(0.87	)	$	0.89	$	(0.22	)	$	2.05
	Diluted		$	(0.87	)	$	0.89	$	(0.22	)	$	2.05
	_______________
	-1	Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.
	-2	Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.
	-3	Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.
	-4	Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.
	-5	The first quarter 2013 loss per unit only applies to earnings from February 14, 2013 (the Partnership's initial public offering date) to December 31, 2013.

Parent_Company_Financial_Infor

Parent Company Financial Information	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Parent Company Financial Information	Parent Company Financial Information
	As discussed in "Note 4 - Debt," certain of our subsidiaries have long-term debt outstanding which place restrictions on distributions of funds to the Partnership. As the Partnership's proportionate share of these subsidiaries' restricted net assets, which totaled approximately $74.0 million at December 31, 2014, represents a significant portion of our consolidated net assets, we are presenting the following parent financial information. The parent only financial information is prepared on the same basis of accounting as our consolidated financial statements, except that our subsidiaries are accounted for under the equity method of accounting.
	NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)
	Balance Sheets
		December 31,
		2014			2013
		(in thousands, except unit amounts)
	ASSETS
	Current assets:
	Cash	$	1,416		$	6,027
	Accounts receivable, net	15,894			8,645
	Derivative contracts	8,248			130
	Other current assets	312			109
	Total current assets	25,870			14,911
	Oil and natural gas properties, at cost using full cost method of accounting:
	Proved oil and natural gas properties	332,413			291,829
	Less: Accumulated depreciation, depletion, and amortization	(153,734		)	(128,961		)
	Total oil and natural gas properties, net	178,679			162,868
	Property and equipment, net	365			—
	Investment in subsidiary	118,185			66,867
	Other assets	3,820			3,661
	Total assets	$	326,919		$	248,307
	LIABILITIES. PARENT NET INVESTMENT AND PARTNERS' CAPITAL:
	Current liabilities:
	Accounts payable and accrued liabilities	$	1,975		$	1,877
	Accounts payable-related parties	4,237			7,348
	Contingent consideration payable	11,572			—
	Derivative contracts	—			3,167
	Other current liabilities	113			—
	Total current liabilities	17,897			12,392
	Long-term debt	83,000			78,500
	Contingent consideration payable	10,801			6,320
	Asset retirement obligations	3,568			3,455
	Other liabilities	339			387
	Total liabilities	115,605			101,054
	Commitments and contingencies
	Unitholders' equity:
	Common units (16,160,381 units issued and outstanding at December 31, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	231,510			151,773
	Common units held in escrow	(6,955		)	—
	Subordinated units (2,205,000 units issued and outstanding at December 31, 2014 and December 31, 2013)	(28,717		)	(17,334		)
	General partner's units (155,102 units issued and outstanding at December 31, 2014 and December 31, 2013)	(1,944		)	(1,174		)
	Total New Source Energy Partners L.P. unitholders' equity	193,894			133,265
	Noncontrolling interest	17,420			13,988
	Total unitholders' equity	211,314			147,253
	Total liabilities and unitholders' equity	$	326,919		$	248,307
	NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)
	Statements of Operations
		For the year ended December 31,
		2014			2013			2012
		(in thousands)
	Revenues:
	Oil sales	$	14,906		$	8,090		$	5,570
	Natural gas sales	15,534			10,000			6,030
	NGL sales	31,048			28,847			23,996
	Total revenues	61,488			46,937			35,596
	Operating costs and expenses:
	Oil, natural gas and NGL production	18,617			12,631			6,217
	Production taxes	2,833			2,669			1,144
	Depreciation, depletion and amortization	24,786			16,590			14,409
	Accretion	327			209			116
	General and administrative	11,051			13,787			12,660
	Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
	Total operating costs and expenses	48,583			44,286			34,546
	Operating income	12,905			2,651			1,050
Other income (expense):
Interest expense	(3,726		)	(4,013		)	(3,202		)
Gain (loss) on derivative contracts, net	10,707			(5,548		)	7,057
Gain on investment in acquired business	2,298			22,709			—
Loss from subsidiary	(64,259		)	(1,303		)	—
(Loss) income before income taxes	(42,075		)	14,496			4,905
Income tax benefit (expense)	—			12,126			(1,796		)
Net (loss) income	(42,075		)	26,622			3,109
Less: net income attributable to noncontrolling interest	242			—			—
Net (loss) income attributable to New Source Energy Partners L.P.	$	(42,317	)	$	26,622		$	3,109
NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)
Statements of Cash Flows
	Year ended December 31,
	2014			2013			2012
	(in thousands)
Cash Flows from Operating Activities:
Net (loss) income	$	(42,075	)	$	26,622		$	3,109
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Earnings from subsidiaries	64,259			1,303			—
Distributions of earnings from subsidiaries	4,406			—			—
Depreciation, depletion and amortization	24,786			16,590			14,409
Accretion	327			209			116
Amortization of deferred loan costs	603			479			603
Write off of loan costs due to debt refinancing	167			1,436			—
Equity-based compensation	644			7,839			8,204
Deferred income tax benefit	—			(12,024		)	1,694
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
Gain on investment in acquired business	(2,298		)	(22,709		)	—
(Gain) loss on derivative contracts, net	(10,707		)	5,548			(7,057		)
Cash (paid) received on settlement of derivative contracts	(1,773		)	(1,929		)	5,987
Payments for premiums on derivatives	—			(1,334		)	—
Changes in operating assets and liabilities:
Accounts receivable	1,096			(9,996		)	881
Other current assets and other assets	(203		)	256			—
Accounts payable and accrued liabilities	(994		)	7,617			(147		)
Net cash provided by operating activities	29,207			18,307			27,799
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	(63,446		)	(22,102		)	—
Additions to oil and natural gas properties	(24,671		)	(28,476		)	(12,162		)
Additions to other property and equipment	(378		)	—			—
Contributions to subsidiaries	(5,000		)	(1,522		)	—
Net cash used in investing activities	(93,495		)	(52,100		)	(12,162		)
Cash Flows from Financing Activities:
Proceeds from borrowings	18,750			80,500			3,000
Payments on borrowings	(14,250		)	(70,000		)	(3,500		)
Payments for deferred loan costs	(356		)	(1,957		)	(64		)
Payment on subordinated note payable to parent	—			(25,000		)	—
Proceeds from sales of common units, net of offering costs	92,375			77,880			—
Proceeds from issuance of common units in private placement, net of offering costs	—			9,833			—
Payments of offering costs	(100		)	(361		)	(1,315		)
Distribution to NSEC	—			(18,295		)	(13,758		)
Distribution to unitholders	(36,742		)	(12,780		)	—
Net cash provided by (used in) financing activities	59,677			39,820			(15,637		)
Net change in cash and cash equivalents	(4,611		)	6,027			—
Cash and cash equivalents, beginning of period	6,027			—			—
Cash and cash equivalents, end of period	$	1,416		$	6,027		$	—

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation. The acquisition of the IPO Properties discussed above was a transaction between businesses under common control. The accounts relating to the IPO Properties have been reflected retroactively in the Partnership’s financial statements at carryover basis. As such, for periods prior to the Offering, the accompanying financial statements have been prepared on a "carve-out" basis from NSEC's financial statements and reflect the historical accounts directly attributable to the IPO Properties together with allocations of expenses from NSEC. Therefore, for periods prior to February 13, 2013, the accompanying consolidated financial statements may not be indicative of the Partnership’s future performance and may not reflect what its financial position, results of operations, and cash flows would have been had it been operated as an independent company during the periods presented. Prior to February 13, 2013, NSEC performed certain corporate functions on behalf of the IPO Properties, and the consolidated financial statements reflect an allocation of the costs NSEC incurred. These functions included executive management, information technology, tax, insurance, accounting, legal and treasury services. The costs of such services were allocated based on the most relevant allocation method to the service provided, primarily based on relative book value of assets, among other factors. Management believes such allocations are reasonable; however, they may not be indicative of the actual expense that would have been incurred had the Partnership been operated as an independent company for all of the periods presented. The charges for these functions are included primarily in general and administrative expenses.
	NSEC became the owner of the IPO Properties on August 12, 2011 and reflected the IPO Properties in its financial statements retroactively because the acquisition of the IPO Properties was a transaction between businesses under common control. Prior to that date, the IPO Properties were owned by a nontaxable entity. NSEC was a taxable entity. Accordingly, on August 12, 2011, NSEC accrued deferred income taxes attributable to differences in the book and tax bases in the IPO Properties and subsequent to the August 12, 2011 acquisition has accounted for income taxes using the asset and liability method until the Offering. The Partnership is not a taxable entity. Accordingly, when NSEC contributed the IPO Properties to the Partnership in 2013, the Partnership reversed the related deferred income taxes, and subsequently the Partnership will not reflect income taxes in its financial statements.
Principles of Consolidation	Principles of Consolidation. The 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.
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 or working capital.
Use of Estimates	Use of Estimates. The preparation of the Partnership’s consolidated financial statements in conformity with 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, fair values of reporting units used in goodwill impairment testing, fair values of other intangible assets used in recording impairments and asset retirement obligations. Actual results could differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents. The Partnership considers all highly liquid investments (i.e., investments which, when purchased, have original maturities of three months or less) to be cash equivalents. Cash is held at financial institutions that are insured by the FDIC. At times, the balance may exceed the federally insured limits.
Accounts Receivable and Allowances	Accounts Receivable and Allowances. Accounts receivable include amounts for sales of oil, natural gas and NGL, as well as amounts due from customers for services performed. The Partnership grants credit to its customers in the ordinary course of business and generally does not require collateral. Customer balances are considered delinquent if unpaid 90 days following the invoice date, and credit privileges may be revoked if balances remain unpaid. Accounts receivable are reviewed and an estimate for losses is provided through an allowance for doubtful accounts when deemed appropriate. In evaluating the level of established reserves, we make judgments regarding our customers’ ability to make required payments, economic events and other factors. As the financial condition of customers changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event we were to determine that a customer may not be able to make required payments, we would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made that they will not be collected.
	Accounts receivable consist of the following as of December 31, 2014 and 2013 (in thousands):
		2014			2013
	Oil, natural gas and NGL sales	$	6,710		$	8,417
	Oil, natural gas and NGL sales - related parties	1,546			228
	Oilfield services	30,668			3,964
		38,924			12,609
	Less: allowance for doubtful accounts	(140		)	—
	Total accounts receivable, net	$	38,784		$	12,609
	Based on management’s assessment of credit history with customers having outstanding balances and current relationships with them, it has concluded that an allowance of $0.1 million was necessary as of December 31, 2014. No allowance for doubtful accounts was deemed necessary as of December 31, 2013. From time to time, the Partnership may factor its accounts receivable. As part of the factoring arrangement, certain receivables are pledged as collateral. See "Note 5 - Factoring Payable" for additional information regarding our factoring arrangements.
Inventory	Inventory. Inventory is stated at the lower of cost or market value, determined on an average cost basis. Inventories consist of consumable materials used during the performance of services and are available for resale. The Partnership assesses the realizability of its inventories based on specific usage and future utility. A charge to cost of sales is taken when factors that would result in a need for reduction in valuation, such as excess or obsolete inventory, are determined. No allowance for obsolescence was deemed necessary as of December 31, 2014 or 2013.
Fair Value of Financial Instruments	Fair Value of Financial Instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Additionally, GAAP requires the use of valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The carrying amounts reflected in the balance sheet for cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and factoring payable approximate the respective fair values due to the short maturities of those instruments. Other financial instruments consist of long-term obligations. The fair value of long-term obligations is estimated based on current interest rates offered to the Partnership for obligations with similar remaining maturities (Level 2). The recorded value of these financial instruments approximated fair value at December 31, 2014 and 2013. See "Note 7 - Fair Value Measurements" for further discussion of our fair value measurements.
	Fair Value of Non-financial Assets and Liabilities. We also apply fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil, natural gas, and NGL production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. We may use the present value of estimated future cash inflows and/or outflows or third-party offers to value non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in "Note 7 - Fair Value Measurements."
Derivative Financial Instruments	Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to expected oil, natural gas and NGL production, we enter into oil, natural gas and NGL derivative contracts. We recognize our derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. We have elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, account for our commodity derivative contracts at fair value with changes in fair value reported currently in earnings. We net derivative assets and liabilities whenever we have a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of our derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statement of cash flows. See "Note 6 - Derivative Contracts" for further discussion of our derivatives.
Oil and Natural Gas Operations	Oil and Natural Gas Operations. 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, natural gas and NGL reserves are capitalized into a full cost pool. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
	Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down is not reversible at a later date. The ceiling limitation calculation is prepared using the 12-month oil, natural gas, and NGL average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil, natural gas, and NGL. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although we have not designated any of our derivative contracts as cash flow hedges and have therefore not included our derivative contracts in estimating future cash flows.
	When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas properties for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.
Property and Equipment	Property and Equipment. Property and equipment is recorded at cost, net of accumulated depreciation. The cost of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the year of disposal. The Partnership calculates depreciation expense using the straight-line method over the assets’ estimated useful lives, which are as follows:
		Estimated Useful Life (in years)
	Vehicles and trailers	3	-	10
	Machinery and equipment	3	-	20
	Office equipment	3	-	7
	Rental irons			10
	Leasehold improvements (1)	3	-	10
	_______________
	(1) Leasehold improvements are depreciated on the straight-line basis over the remaining months of the applicable lease.
	Expenditures for major additions and improvements are capitalized, while minor replacements, maintenance, and repairs that do not improve or extend the life of such assets, are charged to operations as incurred.
Impairment of Long-Lived Assets	Impairment of Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset or asset group to the forecast of undiscounted estimated future net cash flows expected to be generated by the asset or asset group. If such assets are considered to be impaired, the impairment to be recognized is the amount by which the carrying amount of the asset or asset group exceeds our forecast of the discounted estimated future net cash flows directly related to the asset or asset group including disposal value, if any.
	We make estimates and judgments about future undiscounted cash flows and fair values. Although our cash flow forecasts are based on assumptions that are consistent with our plans, there is a significant degree of judgment involved in determining the cash flows attributable to a long-lived asset over its estimated remaining useful life. Our estimates of anticipated cash flows could be reduced significantly in the future and as a result, the carrying amounts of our long-lived assets could be subject to impairment charges in the future.
Intangible Assets - Customer Relationships	Intangible Assets. As part of the acquisition of MCE in November 2013 and acquisitions of MidCentral Completion Services, LLC (“MCCS”), Erick Flowback Services LLC ("EFS") and Rod’s Production Services L.L.C. ("RPS") in June 2014, intangible assets for customer relationships and non-compete agreements were identified and recognized. Amortization for the customer relationship intangible assets was computed using an accelerated method over seven years similar to the expected cash flow pattern of the acquired customer relationships. Amortization for the non-compete agreement intangible asset was based on a straight-line approach over the agreement period. See "Note 8 - Goodwill and Intangible Assets" for additional discussion of our intangible assets and impairment assessment performed in the fourth quarter of 2014.
Goodwill	Goodwill. In conjunction with the acquisitions of MCE, MCCS, EFS and RPS, the Partnership recorded goodwill, which represents the consideration the Partnership paid in excess of the fair value of identifiable assets in the acquisitions. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of November 1 for MCE and April 1 for MCCS, EFS and RPS, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. See "Note 8 - Goodwill and Intangible Assets" for additional discussion of goodwill and impairment assessment performed in the fourth quarter of 2014.
Debt Issuance Costs	Debt Issuance Costs. We amortize debt issuance costs related to our long-term debt as interest expense over the scheduled maturity period of the related debt. We include unamortized debt issuance costs in other assets in the consolidated balance sheet. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.
Contingent Consideration	Contingent Consideration. Contingent consideration, which represents earn out payments in connection with certain of the Partnership’s acquisitions, is recognized at fair value on the acquisition date and remeasured each reporting period with subsequent adjustments to fair value included in general and administrative expenses in the accompanying consolidated statements of operations. The Partnership estimates the fair value of contingent consideration liabilities based on certain performance milestones of the acquired companies or properties, and estimated probabilities of achievement, then discounts the liabilities to present value using the Partnership’s cost of debt. Contingent consideration is valued using significant inputs that are not observable in the market which are defined as Level 3 inputs pursuant to fair value measurement accounting. The Partnership believes its estimates and assumptions are reasonable; however, there is significant judgment involved.
	Changes in the fair value of contingent consideration liabilities may result from changes in discount periods, changes in the timing and amount of sales and/or other specific milestone estimates and changes in probability assumptions with respect to the likelihood of achieving the various earn out criteria. These changes could cause a material impact to, and volatility in our operating results. Earn out payments, if any, will be reflected in cash flows from financing activities and the changes in fair value are reflected in cash flows from operating activities in the consolidated statements of cash flows. See "Note 3 - Contingent Consideration" for additional discussion of our contingent consideration obligations.
Asset Retirement Obligations	Asset Retirement Obligations. We own oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statement of operations. We determine our asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See "Note 13 - Asset Retirement Obligations" for further discussion of our asset retirement obligations.
Revenue Recognition	Revenue Recognition. All revenue is recognized when persuasive evidence of an arrangement exists, the product or service has been provided, the amount is fixed or determinable and collectability is reasonably assured.
	Oil, natural gas and NGL sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil, natural gas, and NGL sales such that revenues are recognized based on the actual proceeds from the oil, natural gas, and NGL sold to purchasers. Oil, natural gas, and NGL imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. For the years ended December 31, 2014 and 2013, there were no significant oil, natural gas, and NGL imbalances.
	Pressure testing services are provided under master service agreements with our customers. Services are typically provided on a day rate or hourly basis. Jobs for these services are typically short-term in nature and range from a few hours to a few days. Revenue is recognized as the services are performed based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and the personnel involved in such services or mobilization. Additional revenue is generated through the sale of consumable supplies that are incidental to the service being performed. The use of consumable supplies is reflected on completed field tickets and billed with the services, as discussed above.
Equity-Based Compensation and Deferred Compensation Plans	Equity-Based Compensation. The Partnership awards common units under its long-term incentive plan. The related expenses reflected in the financial statements are based on the fair value of the Partnership’s equity instruments as of the grant date fair value of those instruments. That cost is recognized as compensation expense over the requisite service period (generally the vesting period).
	Deferred Compensation Plans. In 2014, the Board of Directors of our general partner approved a 401(k) retirement plan for our employees. Under the plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service (“IRS”). For the year ended December 31, 2014, the Company made matching contributions to the plan equal to 100% on the first 3% of employee deferred wages.
Income Taxes	Income Taxes. Income taxes are reflected in these consolidated financial statements during the periods in which the IPO Properties were owned by a taxable entity. Since the Partnership is not a taxable entity, no income taxes have been provided for the periods following completion of the Offering. Upon the Partnership becoming a non-taxable entity, the Partnership recognized a tax benefit related to the change in tax status of approximately $12.1 million for the year ended December 31, 2013.
	We are a limited partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Partnership are passed through to its unitholders. Limited partnerships are subject to Texas margin tax.
	Accounting Standards Codification (“ASC”) Topic 740, Income Taxes, which clarifies the accounting for uncertainties in income taxes recognized in the financial statements, provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of ASC 740 and in subsequent periods. As of and for the years ended December 31, 2014 and 2013, the Partnership did not have any uncertain tax positions, and therefore no adjustments have been made to the financial statements. The tax years 2011 – 2013 remain open to examination for federal income tax purposes. MCES’ income tax returns for the period ended November 12, 2013 and the year ended December 31, 2012 remain subject to potential examination by major tax jurisdictions. Prior to 2012, all entities were single-member LLC’s and were disregarded for tax purposes.
	Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership's book basis in its net assets exceeds the Partnership's net tax basis by $111.2 million at December 31, 2014.
Commitments and Contingencies	Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when an EA and/or remediation activities are probable and costs can be reasonably estimated. See "Note 15 - Commitments and Contingencies" for discussion of our commitments and contingencies.
Concentration of Risk	Concentration of Risk. Our derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating.
	A default by the Partnership under its senior secured revolving credit facility (the “credit facility”) constitutes a default under its derivative contracts with its counterparty that is also a lender under the credit facility. We have master netting agreements with our derivative counterparties, which allow us to net our derivative assets and liabilities with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.
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 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 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.
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, natural gas, and NGL 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.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule of Accounts Receivable	Accounts receivable consist of the following as of December 31, 2014 and 2013 (in thousands):
		2014			2013
	Oil, natural gas and NGL sales	$	6,710		$	8,417
	Oil, natural gas and NGL sales - related parties	1,546			228
	Oilfield services	30,668			3,964
		38,924			12,609
	Less: allowance for doubtful accounts	(140		)	—
	Total accounts receivable, net	$	38,784		$	12,609
Schedule of Useful Lives	The cost of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the year of disposal. The Partnership calculates depreciation expense using the straight-line method over the assets’ estimated useful lives, which are as follows:
		Estimated Useful Life (in years)
	Vehicles and trailers	3	-	10
	Machinery and equipment	3	-	20
	Office equipment	3	-	7
	Rental irons			10
	Leasehold improvements (1)	3	-	10
	_______________
	(1) Leasehold improvements are depreciated on the straight-line basis over the remaining months of the applicable lease.
	Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):
		31-Dec-14			31-Dec-13
	Vehicles and transportation equipment	$	15,891		$	561
	Machinery and equipment	44,441			4,757
	Office furniture and equipment	1,069			79
	Iron	12,258			2,971
	Total	73,659			8,368
	Less: accumulated depreciation	(4,773		)	(202		)
	Property and equipment, net	$	68,886		$	8,166

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	8,165
	Asset retirement obligations	(19		)
	Other liabilities	(254		)
	Total net assets	$	7,892
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Proved oil and natural gas properties	$	29,049
	Other assets	754
	Asset retirement obligations	(1,333		)
	Other liabilities	(488		)
	Total net assets	$	27,982
	The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
	Fair value of assets acquired and liabilities assumed:
	Cash	$	1,522
	Accounts receivable	3,365
	Other current assets	954
	Property and equipment	7,923
	Intangible asset (1)	36,772
	Goodwill (2) (3) (4)	26,678
	Other assets	19
	Total assets acquired	77,233
	Accounts payable and accrued liabilities (3)	(2,448		)
	Factoring payable	(1,679		)
	Long-term debt	(2,335		)
	Total liabilities assumed	(6,462		)
	Net assets acquired	$	70,771
	_______________
	-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 MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.
	-3	Includes purchase price allocation adjustment of $0.1 million made during the third quarter of 2014 based on additional information received on accounts payable assumed.
	-4	Includes purchase price allocation adjustment of $2.6 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.
	Total consideration for the MCE Acquisition is as follows (in thousands):
	Consideration:
	Cash	$	3,781
	Fair value of common units granted (1)	41,822
	Common units granted to MCE employees (2)	2,259
	Contingent consideration (3)	6,320
	MCE Class B units granted (4)	16,589
	Total fair value of consideration	$	70,771
	_______________
	-1	The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).
	-2	The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnership’s long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.
	-3	The owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCES for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $120.0 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCE Contingent Consideration.
	-4	Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See "Note 9 - Equity" for additional discussion of these incentive distributions. The Class B units were valued at $16.6 million through the use of a Monte Carlo simulation. Includes an adjustment of $2.6 million made during the fourth quarter of 2014 to the initial value of these units.
	The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (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's business. 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 (the "CEU Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the CEU Contingent Consideration.
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 3 - Contingent Consideration" for additional discussion of 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 total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
Consideration:
Cash	$	4,260
Fair value of common units granted (1)	8,608
Contingent consideration (2)	1,600
Total fair value of consideration	$	14,468
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	15,190
Asset retirement obligations	(170		)
Other liabilities	(552		)
Total net assets	$	14,468
_______________
-1	The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).
-2	The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideration.
The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	4,888
Asset retirement obligations	(4		)
Other liabilities	(18		)
Total net assets	$	4,866
The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):
Fair value of assets acquired and liabilities assumed:
Cash	$	1,668
Accounts receivable (1)	22,674
Other current assets (2)	620
Property and equipment (2)	43,853
Intangible assets (3)	68,700
Goodwill (4)	14,224
Total assets acquired	151,739
Accounts payable and accrued liabilities (1) (2)	(5,937		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,577		)
Net assets acquired	$	113,162
_______________
-1	Includes purchase price allocation adjustments resulting in an increase totaling $1.2 million during the fourth quarter, based on additional information received primarily on accounts receivable and accrued liabilities.
-2	Includes purchase price allocation adjustments resulting in an increase totaling $1.1 million during the third quarter of 2014, based on additional information received primarily on other current assets and property and equipment acquired.
-3	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.
-4	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. Purchase price allocation adjustments increased the amount assigned to goodwill by approximately $3.7 million in the third quarter of 2014, primarily as a result of an increase to the value of the contingent consideration based on additional information made available. Additional purchase price allocation adjustments in the fourth quarter of 2014 decreased the amount assigned to goodwill by approximately $1.2 million based on additional information received on accounts receivable and accrued liabilities.
The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	3,274
Asset retirement obligations	(24		)
Other liabilities	(20		)
Total net assets	$	3,230
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, which were issued and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition, are excluded from consideration based on the future service requirement for vesting. See "Note 9 - 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 ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million through the use of a probability analysis. See "Note 3 - Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. Includes a purchase price allocation adjustment made during the third quarter of 2014 for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.
Summary of Operating Results
			Year Ended December 31, 2014
			(in thousands)
	Revenue		$	69,167
	Operating loss		$	(2,452	)
			Year Ended December 31, 2013
			(in thousands)
	Revenue		$	11,465
	Excess of revenues over direct operating expenses		$	6,533
Business Acquisition, Pro Forma Information
			Year Ended December 31, 2013
		(in thousands, except per unit amounts)
	Revenue		$	188,232
	Net loss attributable to New Source Energy Partners L.P. (1)		$	(15,931	)
	Net loss per common unit (1):
	Basic		$	(0.98	)
	Diluted		$	(0.98	)
	_______________
	-1	Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the year ended December 31, 2013.
		Year Ended December 31, 2014
		(in thousands, except per unit amounts)
	Revenue	$	227,564
	Net loss attributable to New Source Energy Partners L.P. (1)	$	(32,531	)
	Net loss per common unit (1):
	Basic	$	(1.61	)
	Diluted	$	(1.61	)
	_______________
	-1	Excludes $24.3 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.

Contingent_Consideration_Table

Contingent Consideration (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Business Acquisitions by Acquisition, Contingent Consideration	A reconciliation of the beginning and ending balances of acquisition-related contingent consideration for the years ended December 31, 2014 and 2013 is as follows (in thousands):
		Year Ended December 31,
		2014			2013
	Contingent consideration, beginning balance	$	6,320		$	—
	Acquisition date fair value of contingent consideration - Southern Dome	—			1,600
	Acquisition date fair value of contingent consideration - MCE Acquisition	—			6,320
	Acquisition date fair value of contingent consideration - CEU Acquisition	—			—
	Acquisition date fair value of contingent consideration - MCCS Acquisition	4,057			—
	Acquisition date fair value of contingent consideration - Services Acquisition	21,984			—
	Change in fair value of contingent consideration	(9,031		)	(1,600		)
	Settlement of contingent consideration	—			—
	Contingent consideration, ending balance	23,330			6,320
	Less: current portion of contingent consideration	11,572			—
	Less: offsetting receivable due from former owners	957			—
	Contingent consideration, long-term	$	10,801		$	6,320

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Debt	The Partnership's debt consists of the following (in thousands):
		31-Dec-14			31-Dec-13
	Credit facility	$	83,000		$	78,500
	Notes payable	20,424			2,233
	Line of credit	3,619			—
	Total debt	107,043			80,733
	Less: current maturities of long-term debt	11,825			719
	Long-term debt	$	95,218		$	80,014
Schedule of Maturities of Long-term Debt	The following is a schedule by years of minimum principal payments for debt as of December 31, 2014 (in thousands):
	Year ended December 31,		Amount (1)
	2015		$	11,825
	2016		7,185
	2017 (2)		87,809
	2018		219
	2019		5
	Total		$	107,043
	_______________
	-1	Reflects refinancing of term loan agreement in March 2015.
	-2	Includes credit facility borrowings of $83.0 million maturing in February 2017.

Derivative_Contracts_Tables

Derivative Contracts (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative [Line Items]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table summarizes our derivative contracts on a gross basis, the effects of netting assets and liabilities for which the right of offset exists (in thousands):
	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	)		$	—
	31-Dec-13		Gross Amounts of Recognized Assets and Liabilities				Gross Amounts Offset				Net Amounts Presented
	Assets:
	Commodity derivatives - current assets		$	1,342			$	(1,212	)		$	130
	Commodity derivatives - long-term assets		1,638				(978		)		660
	Total		$	2,980			$	(2,190	)		$	790
	Liabilities:
	Commodity derivatives - current liabilities		$	4,379			$	(1,212	)		$	3,167
	Commodity derivatives - long-term liabilities		1,015				(978		)		37
	Total		$	5,394			$	(2,190	)		$	3,204
	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-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	)
	31-Dec-13		Fair Value Measurements
	Description		Active Markets for Identical Assets (Level 1)				Observable Inputs (Level 2)				Unobservable Inputs (Level 3)				Total Carrying Value
	Oil collars		$	—			$	(57	)		$	—			$	(57	)
	Natural gas collars		—				—				(9		)		(9		)
	Oil put options		—				28				—				28
	Natural gas and NGL put options		—				—				403				403
	Oil and natural gas fixed price swaps		—				132				—				132
	NGL fixed price swaps		—				—				(2,911		)		(2,911		)
	Contingent consideration		—				—				(6,320		)		(6,320		)
	Total		$	—			$	103			$	(8,837	)		$	(8,734	)
	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 years ended December 31, 2014, 2013 and 2012 (in thousands):
			Year Ended December 31,
			2014				2013				2012
	Beginning balance		$	(2,517	)		$	(112	)		$	(1,198	)
	(Loss) gain on derivative contracts		(2,432		)		(4,075		)		7,051
	Transfers out (1)		2,843				—				—
	Cash paid upon settlement		2,106				1,670				(5,965		)
	Ending balance		$	—			$	(2,517	)		$	(112	)
	Unrealized losses included in earnings relating to derivatives held at period end		$	—			$	(2,446	)		$	(112	)
Schedule of Derivative Instruments	At December 31, 2014, 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 put option 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.
Derivative Instruments, Gain (Loss)	The following table presents gain (loss) on our derivative contracts as included in the accompanying consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2014				2013				2012
	Total gain (loss) on derivative contracts, net (1)	$	10,707			$	(5,548	)		$	7,057
Oil Collar [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The following tables present our derivative instruments outstanding as of December 31, 2014:
	Oil collars		Volumes			Floor Price				Ceiling Price
			(Bbls)
	2015		42,649			$	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		36,500			$	77.5			$	92.5			$	102.6
Natural Gas Collars [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Natural gas collars		Volumes			Floor Price				Ceiling Price
			(MMBtu)
	2015		1,362,382			$	4			$	4.32
Natural Gas Options [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Natural gas put options		Volumes			Floor Price
			(MMBtu)
	2015		798,853			$	3.5
	2016		930,468			$	3.5
Oil Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Oil fixed price swaps		Volumes (Bbls)			Weighted Average Fixed Price
	2015		39,411			$	88.9
	2016		36,658			$	86
Natural Gas Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments
	Natural gas fixed price swaps		Volumes			Weighted Average Fixed Price
			(MMBtu)
	2015		800,573			$	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		84,793			$	75.18

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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, the effects of netting assets and liabilities for which the right of offset exists (in thousands):
	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	)	$	—
	31-Dec-13	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset			Net Amounts Presented
	Assets:
	Commodity derivatives - current assets	$	1,342		$	(1,212	)	$	130
	Commodity derivatives - long-term assets	1,638			(978		)	660
	Total	$	2,980		$	(2,190	)	$	790
	Liabilities:
	Commodity derivatives - current liabilities	$	4,379		$	(1,212	)	$	3,167
	Commodity derivatives - long-term liabilities	1,015			(978		)	37
	Total	$	5,394		$	(2,190	)	$	3,204
	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-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	)
	31-Dec-13	Fair Value Measurements
	Description	Active Markets for Identical Assets (Level 1)			Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
	Oil collars	$	—		$	(57	)	$	—		$	(57	)
	Natural gas collars	—			—			(9		)	(9		)
	Oil put options	—			28			—			28
	Natural gas and NGL put options	—			—			403			403
	Oil and natural gas fixed price swaps	—			132			—			132
	NGL fixed price swaps	—			—			(2,911		)	(2,911		)
	Contingent consideration	—			—			(6,320		)	(6,320		)
	Total	$	—		$	103		$	(8,837	)	$	(8,734	)
	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 years ended December 31, 2014, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2014			2013			2012
	Beginning balance	$	(2,517	)	$	(112	)	$	(1,198	)
	(Loss) gain on derivative contracts	(2,432		)	(4,075		)	7,051
	Transfers out (1)	2,843			—			—
	Cash paid upon settlement	2,106			1,670			(5,965		)
	Ending balance	$	—		$	(2,517	)	$	(112	)
	Unrealized losses included in earnings relating to derivatives held at period end	$	—		$	(2,446	)	$	(112	)

Goodwill_and_Intangible_Assets1

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2013 to December 31, 2014 is as follows (in thousands):
	Goodwill at December 31, 2013	$	23,974
	Additions:
	MCCS Acquisition	4,060
	Services Acquisition	11,664
	Change due to purchase price allocation adjustments (1)	4,585
	Impairment	(34,968		)
	Goodwill at December 31, 2014	$	9,315
	_______________
	-1	Includes adjustments totaling $3.8 million during the third quarter of 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. Includes adjustments totaling $1.7 million during the fourth quarter of 2014 as a result of purchase price allocation adjustments of $2.6 million, $(0.7) million and $(0.2) million on the MCE Acquisition, MCCS Acquisition and Services Acquisition, respectively. See "Note 2 - Acquisitions" for discussion of the purchase price allocation adjustments.
Schedule of Finite-Lived Intangible Assets	The Partnership's intangible assets at December 31, 2014 and December 31, 2013 consist of the following (in thousands):
		31-Dec-14			31-Dec-13
	Customer relationships - MCE Acquisition	$	36,772		$	36,772
	Customer relationships - Services Acquisition	64,200			—
	Non-compete agreements - Services Acquisition	4,500			—
	Customer relationships - MCCS Acquisition	1,700			—
	Total intangible assets	107,172			36,772
	Less: accumulated amortization	26,764			1,763
	Impairment	24,031			—
	Intangible assets, net	$	56,377		$	35,009
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	Amortization was estimated by using an accelerated method over seven years similar to the expected cash flow pattern of the acquired customer relationships, estimated for each of the five succeeding years ending December 31, as follows (in thousands):
			Total
	2015		$	19,164
	2016		12,743
	2017		7,976
	2018		4,767
	2019		3,211
	Thereafter		4,766
			$	52,627

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2014
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 years ended December 31, 2014 and 2013, are shown in the following table (in thousands, except per unit amounts):
	Distributions		Payable Date		Distribution per Unit				Common Units				Subordinated Units				General Partner Units		Total
	2014
	First Quarter		15-May-14		$	0.58			$	7,852			$	1,279			$	90	$	9,221
	Second Quarter		15-Aug-14		$	0.585			$	9,025			$	1,290			$	91	$	10,406
	Third Quarter		14-Nov-14		$	0.585			$	9,454			$	1,290			$	91	$	10,835
	Fourth Quarter (3)		13-Feb-15		$	0.2			$	3,281			$	—			$	31	$	3,312
	2013
	First Quarter (1)		15-May-13		$	0.274			$	1,857			$	605			$	43	$	2,505
	Second Quarter		15-Aug-13		$	0.55			$	3,725			$	1,213			$	85	$	5,023
	Third Quarter		15-Nov-13		$	0.575			$	3,895			$	1,268			$	89	$	5,252
	Fourth Quarter (2)		14-Feb-14		$	0.575			$	4,681			$	1,268			$	89	$	6,038
	_______________
	-1	Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit.
	-2	Distributions were not paid on the 1,947,033 common units issued in conjunction with the MCE Acquisition pursuant to an arrangement with the sellers to forgo their rights to distributions for the fourth quarter of 2013 on these units.
	-3	Because the declared common unit distribution is below the Partnership’s Minimum Quarterly Distribution of $0.525 per unit, the Partnership’s subordinated units were not entitled to receive distributions. Under the terms of the partnership agreement, the subordinated units are entitled to distributions once the common unit distribution meets or exceeds the Minimum Quarterly Distribution and all common unit arrearages have been satisfied.
		Total Quarterly				Marginal Percentage Interest in Distributions (1)
		Distributions per Unit				Unitholders		General Partner (2)
	Minimum Quarterly Distribution	$0.53				99%		1%
	First Target Distribution	$0.53	-	$0.60		99%		1%
	Second Target Distribution	$0.60	-	$0.66		86%		14%
	Thereafter	above		$0.66		76%		24%
	_______________
	(1) Represents the percentage interest in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
	(2) Includes the 1% general partner interest as of December 31, 2014 and assumes contribution of any additional capital necessary to maintain the current general partner interest, retention of IDRs by the general partner and no arrearages on common units.
	The following distributions were paid on February 13, 2015 to holders of record as of the close of business on February 2, 2015 (in thousands):
			Common Units				Subordinated Units				General Partner Units				Total
	Distributions		$	3,281			$	—			$	31			$	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 of December 31, 2014, 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%
Schedule of Restricted Equity Awards Activity	Restricted equity, excluding phantom units, activity for the year ended December 31, 2014 and period from February 13, 2013 through December 31, 2013 was as follows:
		Number of Shares			Weighted-Average Grant Date Fair Value
	Granted	467,268			$	20.56
	Vested	—			$	—
	Unvested restricted units outstanding at December 31, 2013	467,268			$	20.56
	Granted	27,275			$	22.63
	Vested	(45,985	)		$	(21.77	)
	Forfeited/Canceled	(2,600	)		$	22.64
	Unvested restricted units outstanding at December 31, 2014	445,958			$	20.51

Earnings_per_Unit_Tables

Earnings per Unit (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	Basic and diluted earnings per unit for the year ended December 31, 2014 and the period February 13, 2013 through December 31, 2013 were computed as follows (in thousands, except per unit amounts):
		Year Ended									February 13, 2013 through
		December 31, 2014									December 31, 2013
		Common Units			Subordinated Units			General Partner			Common Units		Subordinated Units		General Partner
	Net (loss) income	$	(35,652	)	$	(6,256	)	$	(409	)	$	16,929	$	4,099	$	291
	Weighted average units outstanding	13,517			2,205			155			6,995		2,205		155
	Basic and diluted (loss) income per unit	$	(2.64	)	$	(2.84	)	$	(2.64	)	$	2.42	$	1.86	$	1.88

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the years ended December 31, 2014, 2013 and 2012 (in thousands):
		Year Ended December 31,
		2014		2013		2012
	Producing overhead and supervision charges	$	2,905	$	1,636	$	599
	Drilling and completion supervision charges	368		520		27
	Saltwater disposal fees	1,235		696		1,642
	Total expenses incurred	$	4,508	$	2,852	$	2,268

Property_Plant_and_Equipment_T

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	The cost of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the year of disposal. The Partnership calculates depreciation expense using the straight-line method over the assets’ estimated useful lives, which are as follows:
		Estimated Useful Life (in years)
	Vehicles and trailers	3	-	10
	Machinery and equipment	3	-	20
	Office equipment	3	-	7
	Rental irons			10
	Leasehold improvements (1)	3	-	10
	_______________
	(1) Leasehold improvements are depreciated on the straight-line basis over the remaining months of the applicable lease.
	Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):
		31-Dec-14			31-Dec-13
	Vehicles and transportation equipment	$	15,891		$	561
	Machinery and equipment	44,441			4,757
	Office furniture and equipment	1,069			79
	Iron	12,258			2,971
	Total	73,659			8,368
	Less: accumulated depreciation	(4,773		)	(202		)
	Property and equipment, net	$	68,886		$	8,166

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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 years ended December 31, 2014, 2013 and 2012 is as follows (in thousands):
		2014			2013		2012
	Asset retirement obligations at January 1	$	3,455		$	1,510	$	1,411
	Liability incurred upon acquiring and drilling wells	249			1,585		34
	Revisions	(238		)	151		(51		)
	Liability settled or disposed	(112		)	—		—
	Accretion	327			209		116
	Asset retirement obligations at December 31	3,681			3,455		1,510
	Less: current portion	113			—		—
	Asset retirement obligations, net of current	$	3,568		$	3,455	$	1,510

Accounts_Payable_and_Accrued_L1

Accounts Payable and Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Accrued Liabilities	Accounts payable and accrued expenses consist of the following (in thousands):
		December 31,
		2014		2013
	Accounts payable trade	$	9,028	$	1,922
	Accounts payable - other	3,754		318
	Accrued wages and benefits	1,689		338
	Accrued franchise and sales taxes	301		385
	Accrued interest	188		304
	Other	366		—
	Total accounts payable and accrued expenses	$	15,326	$	3,267

Commitments_and_Contingencies_

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases	The following is schedule by year of lease obligations and minimum lease payments for non-cancelable leases with a term of more than one year at December 31, 2014 (in thousands):
	Year
	2015	$	1,299
	2016	1,126
	2017	650
	2018	424
	2019	312
	Thereafter	520
	Total	$	4,331

Business_Segment_Information_T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands):
			Exploration and Production			Oilfield Services (1)			Total
	Year Ended December 31, 2014
	Revenues		$	61,488		$	104,155		$	165,643
	Direct operating expenses		21,450			60,904			82,354
	Segment margin		40,038			43,251			83,289
	General and administrative expenses		11,051			17,620			28,671
	Change in fair value of contingent consideration		(9,031		)	—			(9,031		)
	Impairment		—			59,000			59,000
	Depreciation, depletion, amortization and accretion		25,113			29,566			54,679
	Income (loss) from operations		$	12,905		$	(62,935	)	$	(50,030	)
	Interest expense		$	(3,726	)	$	(1,315	)	$	(5,041	)
	Gain on derivative contracts, net		$	10,707		$	—		$	10,707
	Gain on investment in acquired business		$	2,298		$	—		$	2,298
	Capital expenditures (2)		$	23,662		$	21,349		$	45,011
	At December 31, 2014
	Total assets		$	201,097		$	176,368		$	377,465
	Year Ended December 31, 2013
	Revenues		$	46,937		$	3,738		$	50,675
	Direct operating expenses		15,300			2,040			17,340
	Segment margin		31,637			1,698			33,335
	General and administrative expenses (3)		13,787			973			14,760
	Change in fair value of contingent consideration		(1,600		)	—			(1,600		)
	Depreciation, depletion, amortization and accretion		16,799			1,966			18,765
	Income (loss) from operations		$	2,651		$	(1,241	)	$	1,410
	Interest expense		$	(3,951	)	$	(127	)	$	(4,078	)
	Gain on derivative contracts, net		$	(5,548	)	$	—		$	(5,548	)
	Gain on investment in acquired business		$	22,709		$	—		$	22,709
	Capital expenditures (2)		$	48,319		$	445		$	48,764
	At December 31, 2013
	Total assets		$	181,440		$	73,270		$	254,710
	_______________
	-1	The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See "Note 2 - Acquisitions" for discussion.
	-2	On an accrual basis and exclusive of acquisitions.
	-3	Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.
Schedule of Revenue by Major Customers by Reporting Segments	The following table reflects purchases by customers exceeding 10% of our total sales for the years ended December 31:
	Purchaser		2014		2013	2012
	Scissortail		26%		80%	84%
	United Petroleum Purchasing		< 10%		14%	16%

Subsequent_Events_Tables

Subsequent Events (Tables)	12 Months Ended
	Dec. 31, 2014
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 years ended December 31, 2014 and 2013, are shown in the following table (in thousands, except per unit amounts):
	Distributions		Payable Date		Distribution per Unit				Common Units				Subordinated Units				General Partner Units		Total
	2014
	First Quarter		15-May-14		$	0.58			$	7,852			$	1,279			$	90	$	9,221
	Second Quarter		15-Aug-14		$	0.585			$	9,025			$	1,290			$	91	$	10,406
	Third Quarter		14-Nov-14		$	0.585			$	9,454			$	1,290			$	91	$	10,835
	Fourth Quarter (3)		13-Feb-15		$	0.2			$	3,281			$	—			$	31	$	3,312
	2013
	First Quarter (1)		15-May-13		$	0.274			$	1,857			$	605			$	43	$	2,505
	Second Quarter		15-Aug-13		$	0.55			$	3,725			$	1,213			$	85	$	5,023
	Third Quarter		15-Nov-13		$	0.575			$	3,895			$	1,268			$	89	$	5,252
	Fourth Quarter (2)		14-Feb-14		$	0.575			$	4,681			$	1,268			$	89	$	6,038
	_______________
	-1	Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit.
	-2	Distributions were not paid on the 1,947,033 common units issued in conjunction with the MCE Acquisition pursuant to an arrangement with the sellers to forgo their rights to distributions for the fourth quarter of 2013 on these units.
	-3	Because the declared common unit distribution is below the Partnership’s Minimum Quarterly Distribution of $0.525 per unit, the Partnership’s subordinated units were not entitled to receive distributions. Under the terms of the partnership agreement, the subordinated units are entitled to distributions once the common unit distribution meets or exceeds the Minimum Quarterly Distribution and all common unit arrearages have been satisfied.
		Total Quarterly				Marginal Percentage Interest in Distributions (1)
		Distributions per Unit				Unitholders		General Partner (2)
	Minimum Quarterly Distribution	$0.53				99%		1%
	First Target Distribution	$0.53	-	$0.60		99%		1%
	Second Target Distribution	$0.60	-	$0.66		86%		14%
	Thereafter	above		$0.66		76%		24%
	_______________
	(1) Represents the percentage interest in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
	(2) Includes the 1% general partner interest as of December 31, 2014 and assumes contribution of any additional capital necessary to maintain the current general partner interest, retention of IDRs by the general partner and no arrearages on common units.
	The following distributions were paid on February 13, 2015 to holders of record as of the close of business on February 2, 2015 (in thousands):
			Common Units				Subordinated Units				General Partner Units				Total
	Distributions		$	3,281			$	—			$	31			$	3,312

Supplemental_Information_on_Oi1

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	The Partnership’s capitalized costs for oil, natural gas, and NGL activities consisted of the following (in thousands)
		December 31,
		2014				2013				2012
	Proved	$	332,413			291,829				$	202,795
	Less: accumulated depreciation, depletion and amortization	(153,734		)		(128,961		)		(112,372		)
	Net capitalized costs for oil and natural gas properties	$	178,679			$	162,868			$	90,423
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follow (in thousands):
		Year Ended December 31,
		2014				2013				2012
	Property acquisition costs	$	18,520			$	58,014			$	—
	Development costs	22,793				29,451				11,382
	Total costs incurred	$	41,313			$	87,465			$	11,382
Results of Operations for Oil and Gas Producing Activities Disclosure	The Partnership’s results of operations from oil, natural gas, and NGL producing activities for each of the years 2014, 2013 and 2012 are shown in the following table (in thousands):
		Year Ended December 31,
		2014				2013				2012
	Revenues	$	61,488			$	46,937			$	35,596
	Expenses
	Production	21,450				15,300				7,361
	Depreciation and depletion	24,786				16,590				14,409
	Accretion of asset retirement obligations	327				209				116
	Total expenses	46,563				32,099				21,886
	Results of operations for oil and natural gas producing activities	$	14,925			$	14,838			$	13,710
Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure	The following table summarizes the prices utilized in the reserve estimates as adjusted for location, grade and quality as of December 31:
		Year Ended December 31,
		2014				2013				2012
	Oil	$	91.98			$	93.71			$	92.74
	Natural gas	$	4.13			$	3.55			$	2.59
	NGL	$	34.95			$	35.61			$	33.39
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	Oil and NGL volumes are expressed in Bbls and natural gas volumes are expressed in Mcf.
		Oil			Natural Gas			NGL			Total
		(Bbls)			(Mcf)			(Bbls)			(Boe)
	Total proved reserves
	Balance, January 1, 2012	953,430			21,605,810			9,307,940			13,862,339
	Revisions	(469,630	)		1,295,502			57,825			(195,888	)
	Purchases of reserves	—			—			—			—
	Extensions and discoveries (1)	106,400			3,512,130			1,049,350			1,741,105
	Production	(61,010	)		(2,278,342	)		(711,195	)		(1,151,929	)
	Balance, December 31, 2012	529,190			24,135,100			9,703,920			14,255,627
	Proved developed reserves	249,140			11,980,390			6,182,620			8,428,492
	Proved undeveloped reserves	280,050			12,154,710			3,521,300			5,827,135
	Total proved reserves	529,190			24,135,100			9,703,920			14,255,627
	Balance, January 1, 2013	529,190			24,135,100			9,703,920			14,255,627
	Revisions	(49,507	)		1,897,316			(857,896	)		(591,184	)
	Purchases of reserves	1,031,040			11,889,850			4,727,060			7,739,742
	Extensions and discoveries (1)	13,130			1,092,500			374,390			569,603
	Production	(84,273	)		(2,764,336	)		(790,234	)		(1,335,230	)
	Balance, December 31, 2013	1,439,580			36,250,430			13,157,240			20,638,558
	Proved developed reserves	922,190			19,625,190			8,290,570			12,483,625
	Proved undeveloped reserves	517,390			16,625,240			4,866,670			8,154,933
	Total proved reserves	1,439,580			36,250,430			13,157,240			20,638,558
	Balance, January 1, 2014	1,439,580			36,250,430			13,157,240			20,638,558
	Revisions (2)	(404,382	)		(7,304,864	)		(3,889,584	)		(5,511,443	)
	Purchases of reserves	717,480			5,370,830			247,540			1,860,158
	Extensions and discoveries (3)	60,840			1,849,500			621,580			990,670
	Production	(163,338	)		(3,673,836	)		(885,117	)		(1,660,761	)
	Balance, December 31, 2014	1,650,180			32,492,060			9,251,659			16,317,182
	Proved developed reserves	1,516,850			25,898,620			7,706,900			13,540,186
	Proved undeveloped reserves	133,330			6,593,440			1,544,759			2,776,996
	Total proved reserves	1,650,180			32,492,060			9,251,659			16,317,182
	_______________
	-1	Extensions and discoveries are due to development drilling in the Golden Lane area.
	-2	Revisions are primarily attributable to the reclassification of certain proved undeveloped reserves to probable reserves because our expected drilling plan has been curtailed as a result of low commodity prices and rising costs to drill wells.
	-3	Extensions and discoveries are due to wells drilled in the Golden Lane field in 2014.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	The following table provides the Standardized Measure as of the periods presented below (in thousands):
		2014				2013				2012
	Future production revenues	$	609,362			$	732,340			$	435,670
	Future costs:
	Production	(220,350		)		(223,582		)		(121,541		)
	Development	(48,216		)		(110,881		)		(52,032		)
	Income tax expense(1)	—				—				(85,090		)
	10% annual discount for estimated timing of cash flows	(161,536		)		(185,152		)		(82,746		)
	Standardized measure of discounted net cash flows	$	179,260			$	212,725			$	94,261
	_______________
	-1	Our Standardized Measure as of December 31, 2012 includes effects of income taxes. The Partnership was not a taxable entity in 2013 or 2014.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows	The following table provides a rollforward of the Standardized Measure for the years ended December 31, (in thousands):
		2014				2013				2012
	Discounted future net cash flows at beginning of year	$	212,725			$	94,261			$	153,333
	Increase (decrease)
	Sales and transfers, net of production costs	(40,321		)		(31,637		)		(28,235		)
	Net changes in prices and production costs	2,109				3,952				(93,618		)
	Extensions and discoveries	18,482				25,280				8,688
	Changes in future development costs	9,886				(61,939		)		8,350
	Previous development costs incurred	23,076				29,451				11,382
	Acquisition of reserves in place	29,955				76,596				—
	Revisions of previous quantity estimates	(72,636		)		(7,035		)		(5,833		)
	Changes in income taxes	—				47,387				33,532
	Timing and other	(25,289		)		26,983				(8,671		)
	Accretion of discount	21,273				9,426				15,333
	Net increase (decrease)	(33,465		)		118,464				(59,072		)
	Discounted future net cash flows at end of year	$	179,260			$	212,725			$	94,261

Quarterly_Results_of_Operation1

Quarterly Results of Operations (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The following table summarizes quarterly financial data for the years ended December 31, 2014 and 2013 (in thousands, except per unit data):
			Quarter Ended
	2014		31-Mar			30-Jun		30-Sep			31-Dec
	Revenues		$	27,427		$	26,818	$	56,424		$	54,974
	Income (loss) from operations (1) (2) (3)		2,572			1,690		(5,075		)	(49,217		)
	Income tax expense		—			—		—			—
	Net (loss) income (1) (2) (3)		$	(1,531	)	$	1,586	$	(2,754	)	$	(39,376	)
	(Loss) earnings per common unit
	Basic		$	(0.12	)	$	0.11	$	(0.17	)	$	(2.11	)
	Diluted		$	(0.12	)	$	0.11	$	(0.17	)	$	(2.11	)
	2013
	Revenues		$	9,360		$	10,649	$	12,431		$	18,235
	(Loss) income from operations (4)		(6,118		)	2,456		2,121			2,951
	Income tax benefit		12,126			—		—			—
	Net (loss) income (4)		$	(1,397	)	$	8,151	$	(1,986	)	$	21,854
	(Loss) earnings per common unit (5)
	Basic		$	(0.87	)	$	0.89	$	(0.22	)	$	2.05
	Diluted		$	(0.87	)	$	0.89	$	(0.22	)	$	2.05
	_______________
	-1	Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.
	-2	Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.
	-3	Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.
	-4	Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.
	-5	The first quarter 2013 loss per unit only applies to earnings from February 14, 2013 (the Partnership's initial public offering date) to December 31, 2013.

Parent_Company_Financial_Infor1

Parent Company Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Balance Sheet	NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)
	Balance Sheets
		December 31,
		2014			2013
		(in thousands, except unit amounts)
	ASSETS
	Current assets:
	Cash	$	1,416		$	6,027
	Accounts receivable, net	15,894			8,645
	Derivative contracts	8,248			130
	Other current assets	312			109
	Total current assets	25,870			14,911
	Oil and natural gas properties, at cost using full cost method of accounting:
	Proved oil and natural gas properties	332,413			291,829
	Less: Accumulated depreciation, depletion, and amortization	(153,734		)	(128,961		)
	Total oil and natural gas properties, net	178,679			162,868
	Property and equipment, net	365			—
	Investment in subsidiary	118,185			66,867
	Other assets	3,820			3,661
	Total assets	$	326,919		$	248,307
	LIABILITIES. PARENT NET INVESTMENT AND PARTNERS' CAPITAL:
	Current liabilities:
	Accounts payable and accrued liabilities	$	1,975		$	1,877
	Accounts payable-related parties	4,237			7,348
	Contingent consideration payable	11,572			—
	Derivative contracts	—			3,167
	Other current liabilities	113			—
	Total current liabilities	17,897			12,392
	Long-term debt	83,000			78,500
	Contingent consideration payable	10,801			6,320
	Asset retirement obligations	3,568			3,455
	Other liabilities	339			387
	Total liabilities	115,605			101,054
	Commitments and contingencies
	Unitholders' equity:
	Common units (16,160,381 units issued and outstanding at December 31, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	231,510			151,773
	Common units held in escrow	(6,955		)	—
	Subordinated units (2,205,000 units issued and outstanding at December 31, 2014 and December 31, 2013)	(28,717		)	(17,334		)
	General partner's units (155,102 units issued and outstanding at December 31, 2014 and December 31, 2013)	(1,944		)	(1,174		)
	Total New Source Energy Partners L.P. unitholders' equity	193,894			133,265
	Noncontrolling interest	17,420			13,988
	Total unitholders' equity	211,314			147,253
	Total liabilities and unitholders' equity	$	326,919		$	248,307
Condensed Income Statement	NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)
	Statements of Operations
		For the year ended December 31,
		2014			2013			2012
		(in thousands)
	Revenues:
	Oil sales	$	14,906		$	8,090		$	5,570
	Natural gas sales	15,534			10,000			6,030
	NGL sales	31,048			28,847			23,996
	Total revenues	61,488			46,937			35,596
	Operating costs and expenses:
	Oil, natural gas and NGL production	18,617			12,631			6,217
	Production taxes	2,833			2,669			1,144
	Depreciation, depletion and amortization	24,786			16,590			14,409
	Accretion	327			209			116
	General and administrative	11,051			13,787			12,660
	Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
	Total operating costs and expenses	48,583			44,286			34,546
	Operating income	12,905			2,651			1,050
	Other income (expense):
	Interest expense	(3,726		)	(4,013		)	(3,202		)
	Gain (loss) on derivative contracts, net	10,707			(5,548		)	7,057
	Gain on investment in acquired business	2,298			22,709			—
	Loss from subsidiary	(64,259		)	(1,303		)	—
	(Loss) income before income taxes	(42,075		)	14,496			4,905
	Income tax benefit (expense)	—			12,126			(1,796		)
	Net (loss) income	(42,075		)	26,622			3,109
	Less: net income attributable to noncontrolling interest	242			—			—
	Net (loss) income attributable to New Source Energy Partners L.P.	$	(42,317	)	$	26,622		$	3,109
Condensed Cash Flow Statement	NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)
	Statements of Cash Flows
		Year ended December 31,
		2014			2013			2012
		(in thousands)
	Cash Flows from Operating Activities:
	Net (loss) income	$	(42,075	)	$	26,622		$	3,109
	Adjustments to reconcile net (loss) income to net cash provided by operating activities:
	Earnings from subsidiaries	64,259			1,303			—
	Distributions of earnings from subsidiaries	4,406			—			—
	Depreciation, depletion and amortization	24,786			16,590			14,409
	Accretion	327			209			116
	Amortization of deferred loan costs	603			479			603
	Write off of loan costs due to debt refinancing	167			1,436			—
	Equity-based compensation	644			7,839			8,204
	Deferred income tax benefit	—			(12,024		)	1,694
	Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
	Gain on investment in acquired business	(2,298		)	(22,709		)	—
	(Gain) loss on derivative contracts, net	(10,707		)	5,548			(7,057		)
	Cash (paid) received on settlement of derivative contracts	(1,773		)	(1,929		)	5,987
	Payments for premiums on derivatives	—			(1,334		)	—
	Changes in operating assets and liabilities:
	Accounts receivable	1,096			(9,996		)	881
	Other current assets and other assets	(203		)	256			—
	Accounts payable and accrued liabilities	(994		)	7,617			(147		)
	Net cash provided by operating activities	29,207			18,307			27,799
	Cash Flows from Investing Activities:
	Acquisitions, net of cash acquired	(63,446		)	(22,102		)	—
	Additions to oil and natural gas properties	(24,671		)	(28,476		)	(12,162		)
	Additions to other property and equipment	(378		)	—			—
	Contributions to subsidiaries	(5,000		)	(1,522		)	—
	Net cash used in investing activities	(93,495		)	(52,100		)	(12,162		)
	Cash Flows from Financing Activities:
	Proceeds from borrowings	18,750			80,500			3,000
	Payments on borrowings	(14,250		)	(70,000		)	(3,500		)
	Payments for deferred loan costs	(356		)	(1,957		)	(64		)
	Payment on subordinated note payable to parent	—			(25,000		)	—
	Proceeds from sales of common units, net of offering costs	92,375			77,880			—
	Proceeds from issuance of common units in private placement, net of offering costs	—			9,833			—
	Payments of offering costs	(100		)	(361		)	(1,315		)
	Distribution to NSEC	—			(18,295		)	(13,758		)
	Distribution to unitholders	(36,742		)	(12,780		)	—
	Net cash provided by (used in) financing activities	59,677			39,820			(15,637		)
	Net change in cash and cash equivalents	(4,611		)	6,027			—
	Cash and cash equivalents, beginning of period	6,027			—			—
	Cash and cash equivalents, end of period	$	1,416		$	6,027		$	—

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Narrative (Details) (USD $)	0 Months Ended	2 Months Ended	3 Months Ended								12 Months Ended			1 Months Ended
	Feb. 13, 2013	Mar. 31, 2013	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 28, 2013
Summary of Significant Accounting Policies [Line Items]
Distribution to NSEC											$0	$18,295,000	$13,758,000
Common units issued (in units)			16,160,381				9,599,578				16,160,381	9,599,578
Subordinated units issued (in units)			2,205,000				2,205,000				2,205,000	2,205,000
Receivable issued in offering	25,000,000	25,000,000
Allowance for doubtful accounts			140,000				0				140,000	0
Discount of estimated future net revenues			10.00%								10.00%
Percentage of employer match											100.00%
Percentage of match on employee deferred wages											3.00%
Retirement plan expense											300,000
Income Tax Expense (Benefit)			0	0	0	0	0	0	0	12,126,000	0	-12,126,000	1,796,000
Partnership's net assets in excess of tax basis			111,200,000								111,200,000
IPO [Member]
Summary of Significant Accounting Policies [Line Items]
Issuance of common units, net of offering costs (in units)	4,000,000													4,000,000
Distribution to NSEC	15,800,000	15,800,000
Common units issued (in units)		250,000								250,000
Debt assumed in offering	$70,000,000
New Source Energy GPLLC [Member]
Summary of Significant Accounting Policies [Line Items]
Ownership percentage		50.00%					50.00%			50.00%		50.00%
Common Stock [Member]
Summary of Significant Accounting Policies [Line Items]
Common units issued (in units)	777,500	777,500								777,500
Subordinated Units [Member]
Summary of Significant Accounting Policies [Line Items]
Subordinated units issued (in units)	2,205,000	2,205,000								2,205,000

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Composition of Accounts Receivable (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	$38,924	$12,609
Less: allowance for doubtful accounts	-140	0
Total accounts receivable, net	38,784	12,609
Oil and Natural Gas [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	6,710	8,417
Oil and Natural Gas from Related Parties [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	1,546	228
Oilfield Services [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts Receivable, Gross	$30,668	$3,964

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Schedule of Useful Lives of Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2014
Vehicles and Trailers [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Vehicles and Trailers [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Machinery and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Machinery and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	20 years
Office Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Office Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	7 years
Rental Irons [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Leasehold Improvements [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years	[1]
Leasehold Improvements [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years	[1]
[1]	Leasehold improvements are depreciated on the straight-line basis over the remaining months of the applicable lease.

Acquisitions_Narrative_Details

Acquisitions - Narrative (Details) (USD $)

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

0 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Nov. 12, 2013

Mar. 31, 2013

31-May-13

Jul. 31, 2013

Oct. 31, 2013

Nov. 30, 2013

Jan. 31, 2014

Jun. 26, 2014

Oct. 04, 2013

producing_well

producing_well

Business Acquisition [Line Items]

Contingent consideration

$23,330,000

$23,330,000

$6,320,000

$0

Gain on acquisition of business

2,298,000

22,709,000

0

Purchase price adjustment related to goodwill

1,700,000

3,800,000

4,585,000

[1]

Chief Executive Officer [Member] | MidCentral Energy Services [Member]

Business Acquisition [Line Items]

Ownership percentage of acquired entity

36.00%

Equity method carrying basis in acquisition

1,800,000

Customer Relationships [Member]

Business Acquisition [Line Items]

Useful life of finite-lived intangible asset

7 years

March Acquired Properties [Member]

Business Acquisition [Line Items]

Total fair value of consideration

28,000,000

Units issued in acquisition (in units)

1,378,500

Value of units issued in acquisition (in usd per unit)

$20.30

May Acquired Properties [Member]

Business Acquisition [Line Items]

Total fair value of consideration

7,900,000

July Acquired Properties [Member]

Business Acquisition [Line Items]

Total fair value of consideration

4,900,000

Percentage of working interest acquired

10.00%

Orion Acquisition [Member]

Business Acquisition [Line Items]

Total fair value of consideration

3,200,000

2013 Material Acquisitions [Member]

Business Acquisition [Line Items]

Acquisition expense

2,100,000

Southern Dome [Member]

Business Acquisition [Line Items]

Total fair value of consideration

14,468,000

Value of units issued in acquisition (in usd per unit)

$20.79

Issuance of common units in acquisitions (in units)

414,045

Contingent consideration

0

0

1,600,000

Number of wells Company in which company has acquired working interests

25

MidCentral Energy Services [Member]

Business Acquisition [Line Items]

Total fair value of consideration

70,771,000

Equity interest percentage acquired in acquisition

100.00%

Contingent consideration

0

0

6,320,000

6,320,000

6,320,000

[2]

Class B units issued in MCE acquisition

16,589,000

[3]

Gain on acquisition of business

22,700,000

Purchase price adjustment related to goodwill

2,600,000

100,000

MidCentral Energy Services [Member] | Customer Relationships [Member]

Business Acquisition [Line Items]

Useful life of finite-lived intangible asset

7 years

Intangible Asset

36,772,000

[4]

MidCentral Energy Services [Member] | Maximum [Member]

Business Acquisition [Line Items]

Contingent consideration

120,000,000

120,000,000

120,000,000

MidCentral Energy Services [Member] | MCE Owners [Member]

Business Acquisition [Line Items]

Units issued in acquisition (in units)

1,847,265

Value of units issued in acquisition (in usd per unit)

$22.64

MidCentral Energy Services [Member] | Select MCE Employees [Member]

Business Acquisition [Line Items]

Units issued in acquisition (in units)

99,768

Value of units issued in acquisition (in usd per unit)

$22.64

CEU Paradigm [Member]

Business Acquisition [Line Items]

Total fair value of consideration

17,124,000

Value of units issued in acquisition (in usd per unit)

$23.78

Issuance of common units in acquisitions (in units)

488,667

Contingent consideration

0

0

[5]

Number of wells Company in which company has acquired working interests

23

MCCS [Member]

Business Acquisition [Line Items]

Total fair value of consideration

5,677,000

Value of units issued in acquisition (in usd per unit)

$23.45

Issuance of common units in acquisitions (in units)

33,646

Equity interest percentage acquired in acquisition

100.00%

Contingent consideration

0

0

4,057,000

[6]

Gain on acquisition of business

2,300,000

Purchase price adjustment related to goodwill

-700,000

Intangible Asset

1,700,000

[7]

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

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]

Value of units issued in acquisition (in usd per unit)

$23.45

Issuance of common units in acquisitions (in units)

30,867

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

Value of units issued in acquisition (in usd per unit)

$23.45

Issuance of common units in acquisitions (in units)

1,411,777

Contingent consideration

23,330,000

[8]

23,330,000

[8]

21,984,000

[8]

Purchase price adjustment related to goodwill

-200,000

3,700,000

Intangible Asset

68,700,000

[9]

EFS and RPS [Member] | Phantom Units [Member]

Business Acquisition [Line Items]

Phantom units granted (in units)

432,038

EFS and RPS [Member] | Service Requirement 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

[4]

EFS and RPS [Member] | Noncompete Agreements [Member]

Business Acquisition [Line Items]

Intangible Asset

4,500,000

[4]

2014 Material Acquisitions [Member]

Business Acquisition [Line Items]

Acquisition costs and transaction bonuses

3,600,000

2014 Material Acquisitions [Member] | Acquisition-related Costs [Member]

Business Acquisition [Line Items]

Acquisition costs and transaction bonuses

24,300,000

1,600,000

Accounts Receivable and Accrued Liabilities [Member]

Business Acquisition [Line Items]

Purchase price adjustment related to goodwill

1,200,000

Property, Plant and Equipment [Member] | EFS and RPS [Member]

Business Acquisition [Line Items]

Purchase price adjustment related to goodwill

1,100,000

Contingent Consideration [Member] | EFS and RPS [Member]

Business Acquisition [Line Items]

Purchase price adjustment related to goodwill

$3,700,000

[1]

Includes adjustments totaling $3.8 million during the third quarter of 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. Includes adjustments totaling $1.7 million during the fourth quarter of 2014 as a result of purchase price allocation adjustments of $2.6 million, $(0.7) million and $(0.2) million on the MCE Acquisition, MCCS Acquisition and Services Acquisition, respectively. See "Note 2 - Acquisitions" for discussion of the purchase price allocation adjustments.

[2]

The owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCES for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $120.0 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCE Contingent Consideration.

[3]

Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See "Note 9 - Equity" for additional discussion of these incentive distributions. The Class B units were valued at $16.6 million through the use of a Monte Carlo simulation. Includes an adjustment of $2.6 million made during the fourth quarter of 2014 to the initial value of these units.

[4]

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.

[5]

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 (the "CEU Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

[6]

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 3 - Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

[7]

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

[8]

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 ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million through the use of a probability analysis. See "Note 3 - Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. Includes a purchase price allocation adjustment made during the third quarter of 2014 for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

[9]

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 for March Acquisitions (Details) (March Acquired Properties [Member], USD $)	Mar. 31, 2013
In Thousands, unless otherwise specified
March Acquired Properties [Member]
Business Acquisition [Line Items]
Proved oil and natural gas properties	$29,049
Other assets	754
Asset retirement obligations	-1,333
Other liabilities	-488
Total net assets	$27,982

Acquisitions_Purchase_Price_Al1

Acquisitions - Purchase Price Allocation for May Acquisitions (Details) (May Acquired Properties [Member], USD $)	31-May-13
In Thousands, unless otherwise specified
May Acquired Properties [Member]
Business Acquisition [Line Items]
Proved oil and natural gas properties	$8,165
Asset retirement obligations	-19
Other liabilities	-254
Total net assets	$7,892

Acquisitions_Purchase_Price_Al2

Acquisitions - Purchase Price Allocation for July Acquisitions (Details) (July Acquired Properties [Member], USD $)	Jul. 31, 2013
In Thousands, unless otherwise specified
July Acquired Properties [Member]
Business Acquisition [Line Items]
Proved oil and natural gas properties	$4,888
Asset retirement obligations	-4
Other liabilities	-18
Total net assets	$4,866

Acquisitions_Purchase_Price_Al3

Acquisitions - Purchase Price Allocation for Orion Acquisition (Details) (Orion Acquisition [Member], USD $)	Jul. 31, 2013
In Thousands, unless otherwise specified
Orion Acquisition [Member]
Business Acquisition [Line Items]
Proved oil and natural gas properties	$3,274
Asset retirement obligations	-24
Other liabilities	-20
Total net assets	$3,230

Acquisitions_Purchase_Price_Al4

Acquisitions - Purchase Price Allocation for Southern Dome Acquisition (Details) (Southern Dome [Member], USD $)	1 Months Ended
In Thousands, unless otherwise specified	Oct. 31, 2013
Southern Dome [Member]
Consideration:
Cash	$4,260
Fair value of common units granted	8,608	[1]
Contingent consideration	1,600	[2]
Total fair value of consideration	14,468
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	15,190
Asset retirement obligations	-170
Other liabilities	-552
Total net assets	$14,468
[1]	The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).
[2]	The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideratio

Acquisitions_Purchase_Price_Al5

Acquisitions - Purchase Price Allocation for MCE Acquisition (Details) (USD $)	1 Months Ended
	Nov. 30, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 12, 2013
Business Acquisition [Line Items]
Contingent consideration			$23,330,000	$6,320,000	$0
MidCentral Energy Services [Member]
Business Acquisition [Line Items]
Cash	3,781,000
Contingent consideration	6,320,000	[1]	0	6,320,000		6,320,000
Class B units issued in MCE acquisition	16,589,000	[2]
Total fair value of consideration	70,771,000
MCE Owners [Member] | MidCentral Energy Services [Member]
Business Acquisition [Line Items]
Fair value of units granted	41,822,000	[3]
Select MCE Employees [Member] | MidCentral Energy Services [Member]
Business Acquisition [Line Items]
Fair value of units granted	$2,259,000	[4]
[1]	The owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCES for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $120.0 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCE Contingent Consideration.
[2]	Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See "Note 9 - Equity" for additional discussion of these incentive distributions. The Class B units were valued at $16.6 million through the use of a Monte Carlo simulation. Includes an adjustment of $2.6 million made during the fourth quarter of 2014 to the initial value of these units.
[3]	The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).
[4]	The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnershipbs long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.

Acquisitions_Summary_of_Assets

Acquisitions - Summary of Assets Acquired and Liabilities Assumed in MCE Acquisition (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Nov. 30, 2013
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Goodwill	$9,315	$23,974
MidCentral Energy Services [Member]
Business Acquisition [Line Items]
Cash			1,522
Accounts receivable			3,365
Other current assets			954
Property and equipment			7,923
Goodwill			26,678	[1]
Other assets			19
Total assets acquired			77,233
Accounts payable and accrued liabilities			-2,448	[2]
Factoring payable			-1,679
Long-term debt			-2,335
Total liabilities assumed			-6,462
Total net assets			70,771
Customer Relationships [Member] | MidCentral Energy Services [Member]
Business Acquisition [Line Items]
Intangible Asset			$36,772	[3]
[1]	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 MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.
[2]	Includes purchase price allocation adjustment of $0.1 million made during the third quarter of 2014 based on additional information received on accounts payable assumed.
[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.

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

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Business Acquisition [Line Items]

Revenue

$54,974

$56,424

$26,818

$27,427

$18,235

$12,431

$10,649

$9,360

$165,643

$50,675

$35,596

Income (loss) from operations

-49,217

[1],[2],[3]

-5,075

[1],[2],[3]

1,690

[1],[2],[3]

2,572

[1],[2],[3]

2,951

[4]

2,121

[4]

2,456

[4]

-6,118

[4]

-50,030

1,410

1,050

2013 Material Acquisitions [Member]

Business Acquisition [Line Items]

Revenue

11,465

Income (loss) from operations

6,533

2014 Material Acquisitions [Member]

Business Acquisition [Line Items]

Revenue

69,167

Income (loss) from operations

($2,452)

[1]

Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.

[2]

Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.

[3]

Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.

[4]

Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.

Acquisitions_Purchase_Price_Al6

Acquisitions - Purchase Price Allocation of CEU Acquisition (Details) (USD $)	0 Months Ended
	Jan. 31, 2014		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Business Acquisition [Line Items]
Contingent consideration			$23,330,000	$6,320,000	$0
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]				0
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 (the "CEU Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

Acquisitions_Purchase_Price_Al7

Acquisitions - Purchase Price Allocation for MCCS Acquisition (Details) (USD $)	0 Months Ended
	Jun. 26, 2014		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Contingent consideration			$23,330,000	$6,320,000	$0
Noncontrolling interest			17,420,000	13,988,000
MCCS [Member]
Business Acquisition [Line Items]
Fair value of common units granted	789,000	[1]
Contingent consideration	4,057,000	[2]	0
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 3 - Contingent Consideration" for additional discussion of 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. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.

Acquisitions_Summary_of_Assets1

Acquisitions - Summary of Assets Acquired and Liabilities Assumed in MCCS Acquisition (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Jun. 26, 2014
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Goodwill	$9,315	$23,974
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's business. Goodwill has been allocated to the oilfield services segment. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.

Acquisitions_Purchase_Price_Al8

Acquisitions - Purchase Price Allocation of EFS and RPS Acquisition (Details) (USD $)	0 Months Ended		3 Months Ended
	Jun. 26, 2014		Sep. 30, 2014	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Business Acquisition [Line Items]
Contingent consideration				$23,330,000		$6,320,000	$0
EFS and RPS [Member]
Business Acquisition [Line Items]
Cash	57,348,000
Fair value of common units granted	33,106,000	[1]
Contingent consideration	21,984,000	[2]		23,330,000	[2]
Total fair value of consideration	113,162,000
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Consideration Transferred			-4,800,000
EFS and RPS Employees [Member] | EFS and RPS [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 ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million through the use of a probability analysis. See "Note 3 - Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. Includes a purchase price allocation adjustment made during the third quarter of 2014 for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.
[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, which were issued and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition, are excluded from consideration based on the future service requirement for vesting. See "Note 9 - Equity" for additional discussion of phantom units.

Acquisitions_Summary_of_Assets2

Acquisitions - Summary of Assets Acquired and Liabilities Assumed in EFS and RPS Acquisition (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Jun. 26, 2014
In Thousands, unless otherwise specified
Business Acquisition [Line Items]
Goodwill	$9,315	$23,974
EFS and RPS [Member]
Business Acquisition [Line Items]
Cash			1,668
Accounts receivable			22,674	[1]
Other current assets			620	[2]
Property and equipment			43,853	[2]
Other asset			68,700	[3]
Goodwill			14,224	[4]
Total assets acquired			151,739
Accounts payable and accrued liabilities			-5,937	[1],[2]
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]
Other asset			64,200	[5]
Noncompete Agreements [Member] | EFS and RPS [Member]
Business Acquisition [Line Items]
Other asset			$4,500	[5]
[1]	Includes purchase price allocation adjustments resulting in an increase totaling $1.2 million during the fourth quarter, based on additional information received primarily on accounts receivable and accrued liabilities.
[2]	Includes purchase price allocation adjustments resulting in an increase totaling $1.1 million during the third quarter of 2014, based on additional information received primarily on other current assets and property and equipment acquired.
[3]	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.
[4]	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. Purchase price allocation adjustments increased the amount assigned to goodwill by approximately $3.7 million in the third quarter of 2014, primarily as a result of an increase to the value of the contingent consideration based on additional information made available. Additional purchase price allocation adjustments in the fourth quarter of 2014 decreased the amount assigned to goodwill by approximately $1.2 million based on additional information received on accounts receivable and accrued liabilities.
[5]	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.

Acquisitions_Pro_Forma_Results

Acquisitions - Pro Forma Results of Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
2013 and 2014 Material Acquisitions [Member]
Business Acquisition [Line Items]
Revenue			$188,232,000
Net income			-15,931,000	[1]
Net loss per common unit (1):
Basic (in usd per unit)			($0.98)	[1]
Diluted (in usd per unit)			($0.98)	[1]
2014 Material Acquisitions [Member]
Business Acquisition [Line Items]
Revenue	227,564,000
Net income	-32,531,000	[2]
Net loss per common unit (1):
Basic (in usd per unit)	($1.61)	[2]
Diluted (in usd per unit)	($1.61)	[2]
Acquisition costs and transaction bonuses	-3,600,000
Acquisition-related Costs [Member] | 2014 Material Acquisitions [Member]
Net loss per common unit (1):
Acquisition costs and transaction bonuses	($24,300,000)		($1,600,000)
[1]	Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the year ended December 31, 2013.
[2]	Excludes $24.3 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.

Contingent_Consideration_Recon

Contingent Consideration - Reconciliation of Acquisition Related Accrued Earnouts (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014	Oct. 04, 2013	Nov. 30, 2013		Nov. 12, 2013	Jan. 31, 2014		Jun. 26, 2014
Business Acquisition, Contingent Consideration [Roll Forward]
Contingent consideration, beginning balance	$6,320,000		$0
Acquisition date fair value of contingent consideration	-9,031,000		-1,600,000	0
Change in fair value of contingent consideration	-9,031,000		-1,600,000
Settlement of contingent consideration	0		0
Contingent consideration, ending balance	23,330,000		6,320,000	0
Less: current portion of contingent consideration	11,572,000		0
Less: offsetting receivable due from former owners	957,000		0
Contingent consideration, long-term	10,801,000		6,320,000
Southern Dome [Member]
Business Acquisition, Contingent Consideration [Roll Forward]
Contingent consideration, beginning balance	0				0	1,600,000
Acquisition date fair value of contingent consideration	0		1,600,000
Contingent consideration, ending balance			0		0	1,600,000
MidCentral Energy Services [Member]
Business Acquisition, Contingent Consideration [Roll Forward]
Contingent consideration, beginning balance	6,320,000						6,320,000	[1]	6,320,000
Acquisition date fair value of contingent consideration	0		6,320,000
Contingent consideration, ending balance	0		6,320,000				6,320,000	[1]	6,320,000
CEU Paradigm [Member]
Business Acquisition, Contingent Consideration [Roll Forward]
Contingent consideration, beginning balance					0					0	[2]
Acquisition date fair value of contingent consideration	0		0
Contingent consideration, ending balance					0					0	[2]
MCCS [Member]
Business Acquisition, Contingent Consideration [Roll Forward]
Contingent consideration, beginning balance												4,057,000	[3]
Acquisition date fair value of contingent consideration	4,057,000		0
Contingent consideration, ending balance	0											4,057,000	[3]
EFS and RPS [Member]
Business Acquisition, Contingent Consideration [Roll Forward]
Contingent consideration, beginning balance												21,984,000	[4]
Acquisition date fair value of contingent consideration	21,984,000		0
Contingent consideration, ending balance	$23,330,000	[4]										$21,984,000	[4]
[1]	The owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCES for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $120.0 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCE Contingent Consideration.
[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 (the "CEU Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the CEU Contingent Consideration.
[3]	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 3 - Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.
[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 ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million through the use of a probability analysis. See "Note 3 - Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. Includes a purchase price allocation adjustment made during the third quarter of 2014 for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

Contingent_Consideration_Narra

Contingent Consideration - Narrative (Details) (USD $)

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2013

Nov. 12, 2013

Sep. 30, 2014

Oct. 04, 2013

Jan. 31, 2014

Jun. 26, 2014

Business Acquisition [Line Items]

Contingent consideration

$23,330,000

$6,320,000

$0

Change in fair value of contingent consideration

-9,031,000

-1,600,000

Offsetting receivable on contingent consideration liability from former owners

957,000

0

MidCentral Energy Services [Member]

Business Acquisition [Line Items]

Contingent consideration

0

6,320,000

6,320,000

[1]

6,320,000

Southern Dome [Member]

Business Acquisition [Line Items]

Average daily production needed to provide additional consideration for acquisition (in Boe per day)

383.5

Contingent consideration

0

0

1,600,000

CEU Paradigm [Member]

Business Acquisition [Line Items]

Average daily production needed to provide additional consideration for acquisition (in Boe per day)

566

Contingent consideration

0

0

[2]

MCCS [Member]

Business Acquisition [Line Items]

Contingent consideration

0

4,057,000

[3]

EFS and RPS [Member]

Business Acquisition [Line Items]

Contingent consideration

23,330,000

[4]

21,984,000

[4]

Percentage of contingent consideration to be paid in cash

50.00%

[4]

Percentage of contingent consideration to be paid in common units

50.00%

[4]

Maximum [Member] | MidCentral Energy Services [Member]

Business Acquisition [Line Items]

Contingent consideration

120,000,000

120,000,000

Maximum [Member] | MCCS [Member]

Business Acquisition [Line Items]

Contingent consideration

4,500,000

4,500,000

General and Administrative Expenses [Member] | MidCentral Energy Services [Member]

Business Acquisition [Line Items]

Change in fair value of contingent consideration

-6,300,000

General and Administrative Expenses [Member] | MCCS [Member]

Business Acquisition [Line Items]

Change in fair value of contingent consideration

-4,100,000

General and Administrative Expenses [Member] | EFS and RPS [Member]

Business Acquisition [Line Items]

Change in fair value of contingent consideration

$1,300,000

[1]

The owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCES for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $120.0 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCE Contingent Consideration.

[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 (the "CEU Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

[3]

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 3 - Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

[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 ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million through the use of a probability analysis. See "Note 3 - Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. Includes a purchase price allocation adjustment made during the third quarter of 2014 for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

Debt_Schedule_of_Debt_Details

Debt - Schedule of Debt (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Line of Credit Facility [Line Items]
Outstanding Credit	$83,000	$78,500
Notes payable	20,424	2,233
Total debt	107,043	80,733
Less: current maturities of long-term debt	11,825	719
Long-term debt	95,218	80,014
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Outstanding Credit	$3,619	$0

Debt_Senior_Secured_Revolving_

Debt - Senior Secured Revolving Credit Facility - Narrative (Details) (USD $)	12 Months Ended			2 Months Ended	1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 28, 2015	Apr. 30, 2015	Nov. 01, 2014	Oct. 31, 2014
Debt Instrument [Line Items]
Maximum borrowing base utilization permitted under credit facility	90.00%
Commitment fee percentage	0.50%
Interest rates on debt instruments	3.44%	3.25%
Outstanding balance of line of credit	$83,000,000	$78,500,000
Payments on borrowings	19,814,000	70,102,000	3,500,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit current borrowing capacity						90,000,000	102,500,000
Outstanding balance of line of credit	3,619,000	0
Line of credit remaining borrowing capacity	7,000,000
Available borrowing capacity before distribution restrictions	0
Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Line of credit remaining borrowing capacity				81,000,000
Payments on borrowings				2,000,000
Federal Funds Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	0.50%
London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	1.00%
Minimum [Member]
Debt Instrument [Line Items]
Required ratio of EBITDA to interest expense	2.5
Required current ratio	1
Minimum [Member] | Revolving Credit Facility [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Anticipated decrease in borrowing base					20,000,000
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	2.50%
Minimum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	1.50%
Maximum [Member]
Debt Instrument [Line Items]
Required ratio of total debt to EBITDA	3.5
Maximum [Member] | Revolving Credit Facility [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Anticipated decrease in borrowing base					$30,000,000
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	3.25%
Maximum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	2.25%

Debt_Notes_Payable_Narrative_D

Debt - Notes Payable - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt	107,043,000	[1]
Interest rates on debt instruments	3.44%		3.25%
Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Long-term Debt	7,600,000
Term Loans [Member]
Debt Instrument [Line Items]
Term loans balance	12,900,000
Percentage of excess cash flow to be maintained as balance of reserve account if greater than $0.3 million	100.00%
Term Loans [Member] | Long-term Debt, Noncurrent [Member]
Debt Instrument [Line Items]
Term loans balance	8,300,000
Term Loans [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] | Term Loans [Member]
Debt Instrument [Line Items]
Minimum balance required to be maintained on reserve bank account	325,000
Minimum [Member] | Term Loans [Member] | EFS and RPS [Member]
Debt Instrument [Line Items]
Required fixed-charge ratio	1.25
Required working capital and cash balance	4,000,000
Minimum [Member] | Term Loans [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%
Maximum [Member] | Term Loans [Member] | EFS and RPS [Member]
Debt Instrument [Line Items]
Required leverage ratio	1.5
[1]	Reflects refinancing of term loan agreement in March 2015.

Debt_Line_of_Credit_Narrative_

Debt - Line of Credit - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Nov. 01, 2014	Oct. 31, 2014	Feb. 28, 2014
Line of Credit Facility [Line Items]
Interest rates on debt instruments	3.44%	3.25%
Outstanding balance of line of credit	$83,000,000	$78,500,000
Required debt service coverage ratio	1.25
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit current borrowing capacity			90,000,000	102,500,000
Outstanding balance of line of credit	3,619,000	0
Line of credit remaining borrowing capacity	7,000,000
MidCentral Energy Services [Member] | Revolving Credit Facility [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	3,600,000
Line of credit remaining borrowing capacity	$400,000
Bank of Oklahoma Corporation National Prime Rate [Member] | Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Interest rates on debt instruments	4.00%

Debt_Schedule_of_Longterm_Debt

Debt - Schedule of Long-term Debt Minimum Payments (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Debt Disclosure [Abstract]
2015	$11,825	[1]
2016	7,185	[1]
2017	87,809	[1],[2]
2018	219	[1]
2019	5	[1]
Total	$107,043	[1]
[1]	Reflects refinancing of term loan agreement in March 2015.
[2]	Includes credit facility borrowings of $83.0 million maturing in February 2017.

Factoring_Payable_Narrative_De

Factoring Payable - Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Factoring Payable [Line Items]
Factoring payable	$13,152	$1,907
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
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])	12 Months Ended
	Dec. 31, 2014
	bbl
Oil Collar [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	42,649
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])	12 Months Ended
	Dec. 31, 2014
	bbl
Oil Collars - Three Way [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	36,500
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_Commodity2

Derivative Contracts - Commodity Derivative Positions Natural Gas Collars (Details) (Natural Gas Collars [Member], 2015 [Member])	12 Months Ended
	Dec. 31, 2014
	MMBTU
Natural Gas Collars [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (MMBtu)	1,362,382
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])	12 Months Ended
	Dec. 31, 2014
	MMBTU
2015 [Member]
Derivative [Line Items]
Volumes (MMBtu)	798,853
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 Oil Swaps (Details) (Oil Swaps [Member])	12 Months Ended
	Dec. 31, 2014
	bbl
2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	39,411
Derivative, Swap Type, Average Fixed Price	88.9
2016 [Member]
Derivative [Line Items]
Volumes (Bbls)	36,658
Derivative, Swap Type, Average Fixed Price	86

Derivative_Contracts_Commodity5

Derivative Contracts - Commodity Derivative Positions Natural Gas Swaps (Details) (Natural Gas Swaps [Member])	12 Months Ended
	Dec. 31, 2014
	MMBTU
2015 [Member]
Derivative [Line Items]
Volumes (MMBtu)	800,573
Derivative, Swap Type, Average Fixed Price	4.25
2016 [Member]
Derivative [Line Items]
Volumes (MMBtu)	629,301
Derivative, Swap Type, Average Fixed Price	4.37

Derivative_Contracts_Commodity6

Derivative Contracts - Commodity Derivative Positions Liquid Swaps (Details) (Natural Gas Liquid Swaps [Member], 2015 [Member])	12 Months Ended
	Dec. 31, 2014
	bbl
Natural Gas Liquid Swaps [Member] | 2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	84,793
Derivative, Swap Type, Average Fixed Price	75.18

Derivative_Contracts_Offsettin

Derivative Contracts - Offsetting Commodity Derivative Assets and Liabilities (Details) (Commodity [Member], USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative [Line Items]
Gross amounts of recognized assets	$10,127	$2,980
Gross Amounts Offset	-61	-2,190
Net Amounts Presented	10,066	790
Gross amounts of recognized liabilities	61	5,394
Gross Amounts Offset	-61	-2,190
Net Amounts Presented	0	3,204
Current Assets [Member]
Derivative [Line Items]
Gross amounts of recognized assets	8,309	1,342
Gross Amounts Offset	-61	-1,212
Net Amounts Presented	8,248	130
Long-term Assets [Member]
Derivative [Line Items]
Gross amounts of recognized assets	1,818	1,638
Gross Amounts Offset	0	-978
Net Amounts Presented	1,818	660
Current Liabilities [Member]
Derivative [Line Items]
Gross amounts of recognized liabilities	61	4,379
Gross Amounts Offset	-61	-1,212
Net Amounts Presented	0	3,167
Long-term Liabilities [Member]
Derivative [Line Items]
Gross amounts of recognized liabilities	0	1,015
Gross Amounts Offset	0	-978
Net Amounts Presented	$0	$37

Derivative_Contracts_Gains_Los

Derivative Contracts - Gains (Losses) on Derivative Contracts (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Gain (loss) on derivative contracts, net

$11,500

$3,800

($1,400)

($3,100)

($3,000)

($3,500)

$6,200

($5,300)

$10,707

[1]

($5,548)

[1]

$7,057

[1]

[1]

Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.

Derivative_Contracts_Narrative

Derivative Contracts - Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash (paid) received on settlement of derivative contracts	($1,773)	($1,929)	$5,987

Fair_Value_Measurements_Deriva

Fair Value Measurements - Derivative Assets and Contingent Consideration Measured at Fair Value (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	($23,330,000)	($6,320,000)	$0
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	-2,517,000	-112,000	-1,198,000
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	-23,330,000	-6,320,000
Total	-13,264,000	-8,734,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	0	0
Total	0	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]
Contingent consideration	0	0
Total	10,066,000	103,000
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Contingent consideration	-23,330,000	-6,320,000
Total	-23,330,000	-8,837,000
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	2,411,000
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	2,411,000
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	1,405,000	403,000
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	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	1,405,000	0
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	403,000
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		-57,000
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		-57,000
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		-9,000
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		0
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		-9,000
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		28,000
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		28,000
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, Recurring [Member] | Oil and Natural Gas Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		132,000
Fair Value, Measurements, Recurring [Member] | Oil and Natural Gas 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 and Natural Gas 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		132,000
Fair Value, Measurements, Recurring [Member] | Oil and Natural Gas 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, Natural Gas and NGL Swaps [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, 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	6,250,000
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] | NGL Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		-2,911,000
Fair Value, Measurements, Recurring [Member] | 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] | 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		0
Fair Value, Measurements, Recurring [Member] | 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		($2,911,000)

Fair_Value_Measurements_Fair_V

Fair Value Measurements - Fair Value of Allocated Derivative Assets and Liabilities (Details) (Fair Value, Inputs, Level 3 [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
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)		($112)		($1,198)
(Loss) gain on derivative contracts	-2,432		-4,075		7,051
Transfers out	2,843	[1]	0	[1]	0
Cash paid upon settlement	2,106		1,670		-5,965
Ending balance	0		-2,517		-112
Unrealized losses included in earnings relating to derivatives held at period end	$0		($2,446)		($112)
[1]	Fair values related to the Companybs 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 Companybs internal valuation process, including the use of observable inputs to assess the fair value. During the year ended December 31, 2013, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Companybs policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

Fair_Value_Measurements_Narrat

Fair Value Measurements - Narrative (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value Disclosures [Abstract]
Outstanding balance of line of credit	$83,000	$78,500
Notes payable	$20,424	$2,233

Goodwill_and_Intangible_Assets2

Goodwill and Intangible Assets - Narrative (Details) (USD $)

3 Months Ended

12 Months Ended

1 Months Ended

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2013

Jun. 26, 2014

Finite-Lived Intangible Assets [Line Items]

Goodwill

$9,315,000

$9,315,000

$23,974,000

Change due to purchase price allocation adjustments

-1,700,000

-3,800,000

-4,585,000

[1]

Impairment

34,968,000

Amortization expense

9,400,000

9,400,000

3,100,000

3,100,000

25,000,000

1,800,000

0

Impairment

24,031,000

0

Customer Relationships [Member]

Finite-Lived Intangible Assets [Line Items]

Useful life of finite-lived intangible asset

7 years

MidCentral Energy Services [Member]

Finite-Lived Intangible Assets [Line Items]

Goodwill

26,678,000

[2]

Change due to purchase price allocation adjustments

-2,600,000

-100,000

MidCentral Energy Services [Member] | Customer Relationships [Member]

Finite-Lived Intangible Assets [Line Items]

Useful life of finite-lived intangible asset

7 years

MCCS [Member]

Finite-Lived Intangible Assets [Line Items]

Goodwill

3,382,000

[3]

Change due to purchase price allocation adjustments

700,000

MCCS [Member] | Customer Relationships [Member]

Finite-Lived Intangible Assets [Line Items]

Useful life of finite-lived intangible asset

7 years

EFS and RPS [Member]

Finite-Lived Intangible Assets [Line Items]

Goodwill

14,224,000

[4]

Change due to purchase price allocation adjustments

$200,000

($3,700,000)

EFS and RPS [Member] | Customer Relationships [Member]

Finite-Lived Intangible Assets [Line Items]

Useful life of finite-lived intangible asset

7 years

[1]

Includes adjustments totaling $3.8 million during the third quarter of 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. Includes adjustments totaling $1.7 million during the fourth quarter of 2014 as a result of purchase price allocation adjustments of $2.6 million, $(0.7) million and $(0.2) million on the MCE Acquisition, MCCS Acquisition and Services Acquisition, respectively. See "Note 2 - Acquisitions" for discussion of the purchase price allocation adjustments.

[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 MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.

[3]

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's business. Goodwill has been allocated to the oilfield services segment. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.

[4]

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. Purchase price allocation adjustments increased the amount assigned to goodwill by approximately $3.7 million in the third quarter of 2014, primarily as a result of an increase to the value of the contingent consideration based on additional information made available. Additional purchase price allocation adjustments in the fourth quarter of 2014 decreased the amount assigned to goodwill by approximately $1.2 million based on additional information received on accounts receivable and accrued liabilities.

Goodwill_and_Intangible_Assets3

Goodwill and Intangible Assets - Schedule of Goodwill (Details) (USD $)	3 Months Ended		12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2014		Jun. 26, 2014
Goodwill [Roll Forward]
Goodwill at December 31, 2013			$23,974
Change due to purchase price allocation adjustments	1,700	3,800	4,585	[1]
Impairment			-34,968
Goodwill at December 31, 2014	9,315		9,315
EFS and RPS [Member]
Goodwill [Roll Forward]
Goodwill at December 31, 2013					14,224	[2]
Additions			11,664
Change due to purchase price allocation adjustments	-200	3,700
Goodwill at December 31, 2014					14,224	[2]
MCCS [Member]
Goodwill [Roll Forward]
Goodwill at December 31, 2013					3,382	[3]
Additions			4,060
Change due to purchase price allocation adjustments	-700
Goodwill at December 31, 2014					$3,382	[3]
[1]	Includes adjustments totaling $3.8 million during the third quarter of 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. Includes adjustments totaling $1.7 million during the fourth quarter of 2014 as a result of purchase price allocation adjustments of $2.6 million, $(0.7) million and $(0.2) million on the MCE Acquisition, MCCS Acquisition and Services Acquisition, respectively. See "Note 2 - Acquisitions" for discussion of the purchase price allocation adjustments.
[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. Purchase price allocation adjustments increased the amount assigned to goodwill by approximately $3.7 million in the third quarter of 2014, primarily as a result of an increase to the value of the contingent consideration based on additional information made available. Additional purchase price allocation adjustments in the fourth quarter of 2014 decreased the amount assigned to goodwill by approximately $1.2 million based on additional information received on accounts receivable and accrued liabilities.
[3]	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's business. Goodwill has been allocated to the oilfield services segment. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.

Goodwill_and_Intangible_Assets4

Goodwill and Intangible Assets - Schedule of Finite-Lived Intangible Assets (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	$107,172	$36,772
Less: accumulated amortization	26,764	1,763
Impairment	24,031	0
Intangible assets, net	56,377	35,009
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible assets, net	52,627
MidCentral Energy Services [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	36,772	36,772
EFS and RPS [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	64,200	0
EFS and RPS [Member] | Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	4,500	0
MCCS [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	$1,700	$0

Goodwill_and_Intangible_Assets5

Goodwill and Intangible Assets - Schedule of Future Amortization Expense (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Finite-Lived Intangible Assets [Line Items]
Intangible assets, net	$56,377	$35,009
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
2015	19,164
2016	12,743
2017	7,976
2018	4,767
2019	3,211
Thereafter	4,766
Intangible assets, net	$52,627

Equity_Units_Narrative_Details

Equity - Units - Narrative (Details) (USD $)	0 Months Ended			2 Months Ended	12 Months Ended			1 Months Ended	0 Months Ended	1 Months Ended
	Oct. 06, 2014	Apr. 29, 2014	Feb. 13, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Oct. 03, 2014	Feb. 28, 2013
Class of Stock [Line Items]
Common units issued (in units)					16,160,381	9,599,578		9,599,578
Proceeds from issuance of common stock					$92,375,000	$77,880,000	$0
Payments of distributions to affiliates					0	18,295,000	13,758,000
Subordinated units issued (in units)					2,205,000	2,205,000		2,205,000
Receivable issued in offering			25,000,000	25,000,000
Offering cost related to 2013 private placement paid in 2014						9,833,000
Net proceeds from offering used to repay credit facility		5,000,000
Commission to sales agent	1.75%
Common Stock [Member]
Class of Stock [Line Items]
Common units issued (in units)			777,500	777,500
Units sold in private placement (in units)						465,000		465,000
Offering cost related to 2013 private placement paid in 2014						9,833,000		9,800,000
Subordinated Units [Member]
Class of Stock [Line Items]
Subordinated units issued (in units)			2,205,000	2,205,000
Common Units [Member]
Class of Stock [Line Items]
Units issued in acquisition (in units)					1,964,957	3,739,578
Common partnership units sold in public offering	720,000	3,450,000			4,170,000	4,250,000
Unit price of units sold in public offering		$23.25
Proceeds from public offering of common partnership units		76,200,000							50,000,000
Underwriter's fees associated with public sale of common units		3,600,000
Offering costs associated with public sale of common units		300,000
Proceeds from issuance of equity	16,200,000
New Source Energy GPLLC [Member]
Class of Stock [Line Items]
Ownership percentage				50.00%		50.00%		50.00%
IPO [Member]
Class of Stock [Line Items]
Issuance of common units, net of offering costs (in units)			4,000,000							4,000,000
Share price										$20
Common units issued (in units)				250,000
Proceeds from issuance of common stock				76,600,000
Payments of distributions to affiliates			$15,800,000	$15,800,000

Equity_Distributions_Narrative

Equity - Distributions - Narrative (Details) (USD $)	12 Months Ended	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014
	Boe
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions per Unit	$0.53
Required average quarterly production (in boe per day)	3,200
Primary minimum quarterly distribution on an annualized basis	$2.10
Secondary minimum quarterly distribution on an annualized basis	$2.63
Percentage of secondary minimum quarterly distribution of primary quarterly distribution	125.00%
Days after quarter end in which distributions are declared and distributed	45 days
Required distribution to common units before subordinated units receive distribution	$5.30	$5.30
Common Units [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions paid (in usd per unit)		$0.20

Equity_Summary_of_Incentive_Di

Equity - Summary of Incentive Distribution Rights (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Distributions per Unit		$0.53
Marginal Percentage Interest in Distributions, General Partner	1.00%
Minimum Quarterly Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distributions per Unit		$0.53
Marginal Percentage Interest in Distribution, Unitholders		99.00%	[1]
Marginal Percentage Interest in Distributions, General Partner		1.00%	[1],[2]
First Target Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Marginal Percentage Interest in Distribution, Unitholders		99.00%	[1]
Marginal Percentage Interest in Distributions, General Partner		1.00%	[1],[2]
Second Target Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Marginal Percentage Interest in Distribution, Unitholders		86.00%	[1]
Marginal Percentage Interest in Distributions, General Partner		14.00%	[1],[2]
Thereafter Second Target Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distributions per Unit		$0.66
Marginal Percentage Interest in Distribution, Unitholders		76.00%	[1]
Marginal Percentage Interest in Distributions, General Partner		24.00%	[1],[2]
Minimum [Member] | First Target Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distributions per Unit		$0.53
Minimum [Member] | Second Target Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distributions per Unit		$0.60
Maximum [Member] | First Target Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distributions per Unit		$0.60
Maximum [Member] | Second Target Distribution [Member] | Incentive Distribution [Member]
Distribution Made to Limited Partner [Line Items]
Distributions per Unit		$0.66
[1]	Represents the percentage interest in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column bTotal Quarterly Distribution per Unit.b The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
[2]	Includes the 1% general partner interest as of December 31, 2014 and assumes contribution of any additional capital necessary to maintain the current general partner interest, retention of IDRs by the general partner and no arrearages on common units.

Equity_Schedule_of_Distributio

Equity - Schedule of Distributions (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

In Thousands, except Share data, unless otherwise specified

Jan. 20, 2015

Dec. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Subsequent Event [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions

$3,312

Distributions declared (in usd per unit)

$0.20

Common Units [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions paid (in usd per unit)

$0.20

Units issued in acquisition (in units)

1,964,957

3,739,578

Common Units [Member] | Subsequent Event [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions

3,281

Subordinated Units [Member] | Subsequent Event [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions

0

General Partnership Units [Member] | Subsequent Event [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions

31

Cash Distribution [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions paid (in usd per unit)

$0.20

[1]

$0.59

$0.59

$0.58

$0.57

[2]

$0.57

$0.55

$0.27

[3]

Distributions

3,312

[1]

10,835

10,406

9,221

6,038

[2]

5,252

5,023

2,505

[3]

Prorated period of distribution

47 days

Distributions declared (in usd per unit)

$0.53

Cash Distribution [Member] | Subsequent Event [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions paid (in usd per unit)

$0.53

Cash Distribution [Member] | MidCentral Energy Services [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Units issued in acquisition (in units)

1,947,033

Cash Distribution [Member] | Common Units [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions

3,281

[1]

9,454

9,025

7,852

4,681

[2]

3,895

3,725

1,857

[3]

Cash Distribution [Member] | Subordinated Units [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions

0

[1]

1,290

1,290

1,279

1,268

[2]

1,268

1,213

605

[3]

Cash Distribution [Member] | General Partnership Units [Member]

Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]

Distributions

$31

[1]

$91

$91

$90

$89

[2]

$89

$85

$43

[3]

[1]

Because the declared common unit distribution is below the Partnershipbs Minimum Quarterly Distribution of $0.525 per unit, the Partnershipbs subordinated units were not entitled to receive distributions. Under the terms of the partnership agreement, the subordinated units are entitled to distributions once the common unit distribution meets or exceeds the Minimum Quarterly Distribution and all common unit arrearages have been satisfied.

[2]

Distributions were not paid on the 1,947,033 common units issued in conjunction with the MCE Acquisition pursuant to an arrangement with the sellers to forgo their rights to distributions for the fourth quarter of 2013 on these units

[3]

Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit.

Equity_Noncontrolling_Interest

Equity - Noncontrolling Interest - Narrative (Details) (USD $)	12 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Noncontrolling Interest [Member]
Noncontrolling Interest [Line Items]
Adjustments to target distributions	3.75%
Noncontrolling Interest [Member] | First Target Distribution [Member]
Noncontrolling Interest [Line Items]
Increasing distribution percentage associated with Class B Units	15.00%
Noncontrolling Interest [Member] | Second Target Distribution [Member]
Noncontrolling Interest [Line Items]
Increasing distribution percentage associated with Class B Units	25.00%
Noncontrolling Interest [Member] | Third and Thereafter Target Distribution [Member]
Noncontrolling Interest [Line Items]
Increasing distribution percentage associated with Class B Units	50.00%
Common Class B [Member]
Noncontrolling Interest [Line Items]
Distributions		$0	$200,000	$0	$0

Equity_Allocation_of_Distribut

Equity - Allocation of Distributions (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
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_Equity_Compensation_Nar

Equity - Equity Compensation - Narrative (Details) (USD $)	0 Months Ended		12 Months Ended		1 Months Ended	12 Months Ended	0 Months Ended
In Millions, except Share data, unless otherwise specified	Nov. 12, 2013	Aug. 18, 2011	Dec. 31, 2014	Dec. 31, 2013	Feb. 12, 2013	Dec. 31, 2012	Jun. 26, 2014	Feb. 13, 2013
Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	99,768	2,900,000
Equity based compensation expense			$0.70	$7.50
Restricted Common Units [Member] | Service Requirement Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted	19,490
Recognition period			1 year
Restricted Common Units [Member] | NSEC Stock-Based Compensation [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognition period			1 year 2 months 12 days
Equity based compensation expense					0.4	8.2
Unamortized equity-based compensation expense			0.2
Restricted Common Units [Member] | First Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		1,000,000
Restricted Common Units [Member] | Second Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		700,000
Restricted Common Units [Member] | Third Anniversary [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted		1,200,000
Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity based compensation expense			2.5
Phantom Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Recognition period			1 year 6 months
Phantom units granted (in units)							432,038
Value of phantom units granted							10.1
Fair value of units granted			7.6
Phantom Units [Member] | Maximum [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period							2 years
Phantom Units [Member] | Service Requirement Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units granted (in units)							401,171
Consultants, Officers and Other Employees [Member] | Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares granted								367,500
Equity based compensation expense				$7.40

Equity_Schedule_of_Restricted_

Equity - Schedule of Restricted Equity Awards (Details) (Restricted Common Units [Member], USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Restricted Common Units [Member]
Number of Shares
Beginning Balance	467,268,000
Granted	27,275,000	467,268,000
Vested	-45,985,000	0
Forfeited/Canceled	-2,600,000
Ending Balance	445,958,000	467,268,000
Weighted-Average Grant Date Fair Value
Beginning Balance	$20.56
Granted	$22.63	$20.56
Vested	($21.77)	$0
Forfeited/Canceled	$22.64
Ending Balance	$20.51	$20.56

Earnings_per_Unit_Earnings_Per

Earnings per Unit - Earnings Per Unit (Details) (USD $)

1 Months Ended

3 Months Ended

11 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Feb. 12, 2013

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Common units excluded from EPS calculation because of antidilutive effect

5,349

0

Net loss

$5,303

($39,376)

[1],[2],[3]

($2,754)

[1],[2],[3]

$1,586

[1],[2],[3]

($1,531)

[1],[2],[3]

$21,854

[4]

($1,986)

[4]

$8,151

[4]

($1,397)

[4]

$21,319

($42,317)

$26,622

$3,109

Common Stock Units [Member]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Net loss

16,929

-35,652

Weighted average units outstanding

6,995,000

13,517,000

Basic and diluted income per unit (in usd per unit)

$2.42

($2.64)

Subordinated Units [Member]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Net loss

4,099

-6,256

Weighted average units outstanding

2,205,000

2,205,000

Basic and diluted income per unit (in usd per unit)

$1.86

($2.84)

General Partnership Units [Member]

Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]

Net loss

$291

($409)

Weighted average units outstanding

155,000

155,000

Basic and diluted income per unit (in usd per unit)

$1.88

($2.64)

[1]

Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.

[2]

Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.

[3]

Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.

[4]

Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.

Related_Party_Transactions_Nar

Related Party Transactions - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Related Party Transaction [Line Items]
Leasehold cost obligations	$400,000	$400,000
Charges and fees due to related parties	4,237,000	8,221,000
Service management fees		2,400,000
General and administrative expense	28,671,000	14,760,000	[1]	12,660,000
General Partner [Member]
Related Party Transaction [Line Items]
General and administrative expense	3,900,000
Proceeds from operational advances	1,500,000
Professional fees paid	2,300,000
Board of Directors Chairman [Member]
Related Party Transaction [Line Items]
Ownership percentage of reporting company	25.00%
Percentage of common units owned	15.60%
Percentage of subordinate units owned	100.00%
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Percentage of common units owned	5.60%
Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Percentage of common stock owned	5.30%
New Dominion LLC [Member]
Related Party Transaction [Line Items]
Charges and fees due to related parties	1,900,000	1,300,000
Chief Financial Officer [Member]
Related Party Transaction [Line Items]
Professional fees paid	400,000
Ownership percentage in Finley & Cook	31.50%
Subordinated Units [Member] | Board of Directors Chairman [Member]
Related Party Transaction [Line Items]
Number of subordinate units owned	2,205,000
General Partner [Member] | Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Ownership percentage of reporting company	69.40%
MCCS [Member]
Related Party Transaction [Line Items]
Payment to Related Party	$700,000
MidCentral Energy Services [Member] | MidCentral Energy Services [Member] | Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Ownership percentage of acquired entity	36.00%
MidCentral Energy Services [Member] | MidCentral Energy Services [Member] | President [Member]
Related Party Transaction [Line Items]
Ownership percentage of acquired entity	36.00%
[1]	Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

Related_Party_Transactions_Sum

Related Party Transactions - Summary of Related Party Transactions (Details) (New Dominion LLC [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Related Party Costs	$4,508	$2,852	$2,268
Producing Overhead Charges [Member]
Related Party Transaction [Line Items]
Related Party Costs	2,905	1,636	599
Drilling And Completion Overhead Charges [Member]
Related Party Transaction [Line Items]
Related Party Costs	368	520	27
Saltwater Disposal Fees [Member]
Related Party Transaction [Line Items]
Related Party Costs	$1,235	$696	$1,642

Property_Plant_and_Equipment_N

Property, Plant and Equipment - Narrative (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Abstract]
Average rates used for depletion of oil and natural gas properties	14.92	12.42	12.51

Property_Plant_and_Equipment_S

Property, Plant and Equipment - Schedule of Property and Equipment (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment [Line Items]
Property and equipment, net	$68,886	$8,166
Oilfield Services [Member]
Property, Plant and Equipment [Line Items]
Total	73,659	8,368
Less: accumulated depreciation	-4,773	-202
Property and equipment, net	68,886	8,166
Oilfield Services [Member] | Vehicles and Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	15,891	561
Oilfield Services [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	44,441	4,757
Oilfield Services [Member] | Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	1,069	79
Oilfield Services [Member] | Iron [Member]
Property, Plant and Equipment [Line Items]
Total	$12,258	$2,971

Asset_Retirement_Obligations_C

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1	$3,455	$1,510	$1,411
Liability incurred upon acquiring and drilling wells	249	1,585	34
Revisions	-238	151	-51
Liability settled or disposed	-112	0	0
Accretion	327	209	116
Asset retirement obligations at December 31	3,681	3,455	1,510
Less: current portion	113	0	0
Asset retirement obligations, net of current	$3,568	$3,455	$1,510

Accounts_Payable_and_Accrued_L2

Accounts Payable and Accrued Liabilities - Schedule of Accounts Payable and Accrued Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Payables and Accruals [Abstract]
Accounts payable trade	$9,028	$1,922
Accounts payable - other	3,754	318
Accrued wages and benefits	1,689	338
Accrued franchise and sales taxes	301	385
Accrued interest	188	304
Other	366	0
Total accounts payable and accrued expenses	$15,326	$3,267

Commitments_and_Contingencies_1

Commitments and Contingencies - Narrative (Details) (USD $)	12 Months Ended		0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Jan. 29, 2015	Jan. 12, 2015
Loss Contingencies [Line Items]
Annual maintenance drilling budget	$8,200,000
Maintenance budget incurred to date	23,100,000
Estimated contingency loss	250,000
Rental expense, operating leases	800,000	100,000
Affiliated Entity [Member]
Loss Contingencies [Line Items]
Percentage of common units owned	5.60%
Board of Directors Chairman [Member]
Loss Contingencies [Line Items]
Percentage of common units owned	15.60%
Subsequent Event [Member]
Loss Contingencies [Line Items]
Purported claims total			$1,900,000
Subsequent Event [Member] | Affiliated Entity [Member]
Loss Contingencies [Line Items]
Percentage of common units owned				30.60%
Subsequent Event [Member] | Board of Directors Chairman [Member]
Loss Contingencies [Line Items]
Percentage of common units owned				15.60%

Commitments_and_Contingencies_2

Commitments and Contingencies - Schedule of Future Minimum Payments of Operating Leases (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Commitments and Contingencies Disclosure [Abstract]
2015	$1,299
2016	1,126
2017	650
2018	424
2019	312
Thereafter	520
Total	$4,331

Business_Segment_Information_N

Business Segment Information - Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	segment
Segment Reporting Information [Line Items]
Number of operating segments	2
Equity-based compensation	$3,233	$7,839	$8,204
Exploration and Production [Member] | General and Administrative Expenses [Member]
Segment Reporting Information [Line Items]
Equity-based compensation		$7,700

Business_Segment_Information_S

Business Segment Information - Summary of Segment Operating Activities (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenue	$54,974		$56,424		$26,818		$27,427		$18,235		$12,431		$10,649		$9,360		$165,643		$50,675		$35,596
Direct operating expenses																	82,354		17,340
Segment margin																	83,289		33,335
General and administrative																	28,671		14,760	[1]	12,660
Change in fair value of contingent consideration																	-9,031		-1,600		0
Impairment of goodwill and other intangible assets																	59,000		0		0
Depreciation, depletion, amortization and accretion																	54,679		18,765
Operating (loss) income	-49,217	[2],[3],[4]	-5,075	[2],[3],[4]	1,690	[2],[3],[4]	2,572	[2],[3],[4]	2,951	[5]	2,121	[5]	2,456	[5]	-6,118	[5]	-50,030		1,410		1,050
Interest expense																	-5,041		-4,078		-3,202
Gain (loss) on derivative contracts, net	11,500		3,800		-1,400		-3,100		-3,000		-3,500		6,200		-5,300		10,707	[6]	-5,548	[6]	7,057	[6]
Gain on investment in acquired business																	2,298		22,709		0
Property, Plant and Equipment, Additions																	45,011	[7]	48,764	[7]
Total assets	377,465								254,710								377,465		254,710
Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenue																	61,488		46,937
Direct operating expenses																	21,450		15,300
Segment margin																	40,038		31,637
General and administrative																	11,051		13,787	[1]
Change in fair value of contingent consideration																	-9,031		-1,600
Impairment of goodwill and other intangible assets																	0
Depreciation, depletion, amortization and accretion																	25,113		16,799
Operating (loss) income																	12,905		2,651
Interest expense																	-3,726		-3,951
Gain (loss) on derivative contracts, net																	10,707		-5,548
Gain on investment in acquired business																	2,298		22,709
Property, Plant and Equipment, Additions																	23,662	[7]	48,319	[7]
Total assets	201,097								181,440								201,097		181,440
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Revenue																	104,155	[8]	3,738	[8]
Direct operating expenses																	60,904	[8]	2,040	[8]
Segment margin																	43,251	[8]	1,698	[8]
General and administrative																	17,620	[8]	973	[1],[8]
Change in fair value of contingent consideration																	0	[8]	0	[8]
Impairment of goodwill and other intangible assets																	59,000	[8]
Depreciation, depletion, amortization and accretion																	29,566	[8]	1,966	[8]
Operating (loss) income																	-62,935	[8]	-1,241	[8]
Interest expense																	-1,315	[8]	-127	[8]
Gain (loss) on derivative contracts, net																	0	[8]	0	[8]
Gain on investment in acquired business																	0	[8]	0	[8]
Property, Plant and Equipment, Additions																	21,349	[7],[8]	445	[7],[8]
Total assets	$176,368	[8]							$73,270	[8]							$176,368	[8]	$73,270	[8]
[1]	Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.
[2]	Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.
[3]	Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.
[4]	Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.
[5]	Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.
[6]	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.
[7]	On an accrual basis and exclusive of acquisitions.
[8]	The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See "Note 2 - Acquisitions" for discussion.

Business_Segment_Information_O

Business Segment Information - Oil and Natural Gas Sales by Customer (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Scissortail [Member]
Concentration Risk [Line Items]
Major customers concentration risk percentage (less than 10% in 2011 for United Petroleum Purchasing)	26.00%	80.00%	84.00%
United Petroleum Purchasing [Member]
Concentration Risk [Line Items]
Major customers concentration risk percentage (less than 10% in 2011 for United Petroleum Purchasing)		14.00%	16.00%

Subsequent_Events_Narrative_De

Subsequent Events - Narrative (Details) (USD $)

3 Months Ended

0 Months Ended

In Millions, except Per Share data, unless otherwise specified

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Jan. 20, 2015

Jan. 09, 2015

Feb. 24, 2015

Cash Distribution [Member]

Subsequent Event [Line Items]

Distributions declared (in usd per unit)

$0.53

Distributions paid (in usd per unit)

$0.20

[1]

$0.59

$0.59

$0.58

$0.57

[2]

$0.57

$0.55

$0.27

[3]

Subsequent Event [Member]

Subsequent Event [Line Items]

Distributions declared (in usd per unit)

$0.20

Subsequent Event [Member] | MidCentral Energy Partners LP [Member]

Subsequent Event [Line Items]

Number of parcels of real estate acquired

2

Sales of real property

$0.90

Subsequent Event [Member] | MidCentral Energy Partners LP [Member] | Canadian County, OK [Member]

Subsequent Event [Line Items]

Number of parcels of real estate acquired

1

Subsequent Event [Member] | MidCentral Energy Partners LP [Member] | Ector County, TX [Member]

Subsequent Event [Line Items]

Number of parcels of real estate acquired

1

Subsequent Event [Member] | MidCentral Energy Partners LP [Member] | Kansas County, TX [Member]

Subsequent Event [Line Items]

Sales of real property

$0.50

Subsequent Event [Member] | Chief Executive Officer [Member] | MidCentral Energy Partners LP [Member]

Subsequent Event [Line Items]

Ownership percentage

50.00%

50.00%

Subsequent Event [Member] | Chief Operating Officer [Member] | MidCentral Energy Partners LP [Member]

Subsequent Event [Line Items]

Ownership percentage

50.00%

50.00%

Subsequent Event [Member] | Cash Distribution [Member]

Subsequent Event [Line Items]

Distributions paid (in usd per unit)

$0.53

[1]

Because the declared common unit distribution is below the Partnershipbs Minimum Quarterly Distribution of $0.525 per unit, the Partnershipbs subordinated units were not entitled to receive distributions. Under the terms of the partnership agreement, the subordinated units are entitled to distributions once the common unit distribution meets or exceeds the Minimum Quarterly Distribution and all common unit arrearages have been satisfied.

[2]

Distributions were not paid on the 1,947,033 common units issued in conjunction with the MCE Acquisition pursuant to an arrangement with the sellers to forgo their rights to distributions for the fourth quarter of 2013 on these units

[3]

Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit.

Subsequent_Events_Schedule_of_

Subsequent Events - Schedule of Distributions (Details) (Subsequent Event [Member], USD $)	0 Months Ended
In Thousands, unless otherwise specified	Jan. 20, 2015
Subsequent Event [Line Items]
Distributions	$3,312
Common Units [Member]
Subsequent Event [Line Items]
Distributions	3,281
Subordinated Units [Member]
Subsequent Event [Line Items]
Distributions	0
General Partnership Units [Member]
Subsequent Event [Line Items]
Distributions	$31

Supplemental_Information_on_Oi2

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Capitalized Costs Related to Oil and Natural Gas Producing Activities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved	$332,413	$291,829	$202,795
Less: accumulated depreciation, depletion and amortization	-153,734	-128,961	-112,372
Total oil and natural gas properties, net	$178,679	$162,868	$90,423

Supplemental_Information_on_Oi3

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition and Development (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property acquisition costs	$18,520	$58,014	$0
Development costs	22,793	29,451	11,382
Total costs incurred	$41,313	$87,465	$11,382

Supplemental_Information_on_Oi4

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Results of Operations for Oil, Natural Gas, and NGL Producing Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Revenues	$61,488	$46,937	$35,596
Expenses
Production	21,450	15,300	7,361
Depreciation and depletion	24,786	16,590	14,409
Accretion of asset retirement obligations	327	209	116
Total expenses	46,563	32,099	21,886
Results of operations for oil and natural gas producing activities	$14,925	$14,838	$13,710

Supplemental_Information_on_Oi5

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Narrative (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	91.98	93.71	92.74
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	4.13	3.55	2.59
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	34.95	35.61	33.39
Price of NGLs as compared to oil prices	38.00%	38.00%	36.00%
West Texas Intermediate [Member] | Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	94.99	96.78	2.76
Henry Hub Spot [Member] | Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	4.35	3.67	94.71

Supplemental_Information_on_Oi6

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Prices Utilized in Reserve Estimates (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	91.98	93.71	92.74
Natural Gas [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	4.13	3.55	2.59
Natural Gas Liquids [Member]
Average Sales Price and Production Costs Per Unit of Production [Line Items]
Prices used in estimates	34.95	35.61	33.39

Supplemental_Information_on_Oi7

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Rollforward of Total Net Proved Reserves (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	Boe		Boe		Boe
Proved Developed and Undeveloped Reserve (Energy) [Roll Forward]
Beginning Balance (in BOE)	20,638,558		14,255,627		13,862,339
Revisions (in BOE)	-5,511,443	[1]	-591,184		-195,888
Purchases of reserves (in BOE)	1,860,158		7,739,742		0
Extensions and discoveries (in BOE)	990,670	[2]	569,603	[3]	1,741,105	[3]
Production (in BOE)	-1,660,761		-1,335,230		-1,151,929
Ending Balance (in BOE)	16,317,182		20,638,558		14,255,627
Proved developed reserves (in BOE)	13,540,186		12,483,625		8,428,492
Proved undeveloped reserves (in BOE)	2,776,996		8,154,933		5,827,135
Oil [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning Balance (Mcf for Natural Gas)	1,439,580		529,190		953,430
Revisions (Mcf for Natural Gas)	-404,382	[1]	-49,507		-469,630
Purchases of reserves (Mcf for Natural Gas)	717,480		1,031,040		0
Extensions and discoveries (Mcf for Natural Gas)	60,840	[2]	13,130	[3]	106,400	[3]
Production (Mcf for Natural Gas)	-163,338		-84,273		-61,010
Ending Balance (Mcf for Natural Gas)	1,650,180		1,439,580		529,190
Proved developed reserves (Mcf for Natural Gas)	1,516,850		922,190		249,140
Proved undeveloped reserves (Mcf for Natural Gas)	133,330		517,390		280,050
Natural Gas [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning Balance (Mcf for Natural Gas)	36,250,430		24,135,100		21,605,810
Revisions (Mcf for Natural Gas)	-7,304,864	[1]	1,897,316		1,295,502
Purchases of reserves (Mcf for Natural Gas)	5,370,830		11,889,850		0
Extensions and discoveries (Mcf for Natural Gas)	1,849,500	[2]	1,092,500	[3]	3,512,130	[3]
Production (Mcf for Natural Gas)	-3,673,836		-2,764,336		-2,278,342
Ending Balance (Mcf for Natural Gas)	32,492,060		36,250,430		24,135,100
Proved developed reserves (Mcf for Natural Gas)	25,898,620		19,625,190		11,980,390
Proved undeveloped reserves (Mcf for Natural Gas)	6,593,440		16,625,240		12,154,710
Natural Gas Liquids [Member]
Proved Developed and Undeveloped Reserves [Abstract]
Beginning Balance (Mcf for Natural Gas)	13,157,240		9,703,920		9,307,940
Revisions (Mcf for Natural Gas)	-3,889,584	[1]	-857,896		57,825
Purchases of reserves (Mcf for Natural Gas)	247,540		4,727,060		0
Extensions and discoveries (Mcf for Natural Gas)	621,580	[2]	374,390	[3]	1,049,350	[3]
Production (Mcf for Natural Gas)	-885,117		-790,234		-711,195
Ending Balance (Mcf for Natural Gas)	9,251,659		13,157,240		9,703,920
Proved developed reserves (Mcf for Natural Gas)	7,706,900		8,290,570		6,182,620
Proved undeveloped reserves (Mcf for Natural Gas)	1,544,759		4,866,670		3,521,300
[1]	Revisions are primarily attributable to the reclassification of certain proved undeveloped reserves to probable reserves because our expected drilling plan has been curtailed as a result of low commodity prices and rising costs to drill wells.
[2]	Extensions and discoveries are due to wells drilled in the Golden Lane field in 2014.
[3]	Extensions and discoveries are due to development drilling in the Golden Lane area.

Supplemental_Information_on_Oi8

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future production revenues	$609,362	$732,340	$435,670
Production	-220,350	-223,582	-121,541
Development	-48,216	-110,881	-52,032
Income tax expense	0	0	-85,090
10% annual discount for estimated timing of cash flows	-161,536	-185,152	-82,746
Standardized measure of discounted net cash flows	$179,260	$212,725	$94,261	$153,333

Supplemental_Information_on_Oi9

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Discounted future net cash flows at beginning of year	$212,725	$94,261	$153,333
Sales and transfers, net of production costs	-40,321	-31,637	-28,235
Net changes in prices and production costs	2,109	3,952	-93,618
Extensions and discoveries	18,482	25,280	8,688
Changes in future development costs	9,886	-61,939	8,350
Previous development costs incurred	23,076	29,451	11,382
Acquisition of reserves in place	29,955	76,596	0
Revisions of previous quantity estimates	-72,636	-7,035	-5,833
Changes in income taxes	0	47,387	33,532
Timing and other	-25,289	26,983	-8,671
Accretion of discount	21,273	9,426	15,333
Net increase (decrease)	-33,465	118,464	-59,072
Discounted future net cash flows at end of year	$179,260	$212,725	$94,261

Quarterly_Results_of_Operation2

Quarterly Results of Operations (unaudited) (Details) (USD $)	1 Months Ended	3 Months Ended																11 Months Ended	12 Months Ended
	Feb. 12, 2013	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Quarterly Financial Information Disclosure [Abstract]
Revenues		$54,974,000		$56,424,000		$26,818,000		$27,427,000		$18,235,000		$12,431,000		$10,649,000		$9,360,000			$165,643,000		$50,675,000		$35,596,000
Income (loss) from operations		-49,217,000	[1],[2],[3]	-5,075,000	[1],[2],[3]	1,690,000	[1],[2],[3]	2,572,000	[1],[2],[3]	2,951,000	[4]	2,121,000	[4]	2,456,000	[4]	-6,118,000	[4]		-50,030,000		1,410,000		1,050,000
Income tax benefit (expense)		0		0		0		0		0		0		0		-12,126,000			0		12,126,000		-1,796,000
Net Income (Loss) Attributable to Parent	5,303,000	-39,376,000	[1],[2],[3]	-2,754,000	[1],[2],[3]	1,586,000	[1],[2],[3]	-1,531,000	[1],[2],[3]	21,854,000	[4]	-1,986,000	[4]	8,151,000	[4]	-1,397,000	[4]	21,319,000	-42,317,000		26,622,000		3,109,000
Basic earnings (loss) per unit (in usd per unit)		($2.11)		($0.17)		$0.11		($0.12)		$2.05	[5]	($0.22)	[5]	$0.89	[5]	($0.87)	[5]
Diluted earnings (loss) per unit (in usd per unit)		($2.11)		($0.17)		$0.11		($0.12)		$2.05	[5]	($0.22)	[5]	$0.89	[5]	($0.87)	[5]
Amortization expense		9,400,000		9,400,000		3,100,000		3,100,000											25,000,000		1,800,000		0
Gain (loss) on derivative contracts, net		11,500,000		3,800,000		-1,400,000		-3,100,000		-3,000,000		-3,500,000		6,200,000		-5,300,000			10,707,000	[6]	-5,548,000	[6]	7,057,000	[6]
Impairment on goodwill																			-34,968,000
Impairment on intangible assets																			$24,031,000		$0
[1]	Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.
[2]	Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.
[3]	Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.
[4]	Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.
[5]	The first quarter 2013 loss per unit only applies to earnings from February 14, 2013 (the Partnership's initial public offering date) to December 31, 2013.
[6]	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.

Parent_Company_Financial_Infor2

Parent Company Financial Information - Narrative (Details) (Subsidiaries [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Restricted net assets	$74

Parent_Company_Financial_Infor3

Parent Company Financial Information - New Source Energy Partners L.P. (Parent Only) - Balance Sheets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:
Cash	$5,504	$7,291
Accounts receivable, net	38,784	12,609
Derivative contracts	8,248	130
Other current assets	3,116	822
Total current assets	60,238	21,014
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	332,413	291,829	202,795
Less: Accumulated depreciation, depletion, and amortization	-153,734	-128,961	-112,372
Total oil and natural gas properties, net	178,679	162,868	90,423
Property and equipment, net	68,886	8,166
Other assets	2,152	3,019
Total assets	377,465	254,710
Current liabilities:
Accounts payable and accrued liabilities	15,326	3,267
Accounts payable-related parties	4,237	8,221
Contingent consideration payable	11,572	0
Derivative contracts	0	3,167
Total current liabilities	56,225	17,281
Long-term debt	95,218	80,014
Contingent consideration payable	10,801	6,320
Asset retirement obligations	3,568	3,455	1,510
Other liabilities	339	387
Total liabilities	166,151	107,457
Commitments and contingencies
Unitholders' equity:
Common units (16,160,381 units issued and outstanding at December 31, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	231,510	151,773
Common units held in escrow	-6,955	0
Subordinated units (2,205,000 units issued and outstanding at December 31, 2014 and December 31, 2013)	-28,717	-17,334
General partner's units (155,102 units issued and outstanding at December 31, 2014 and December 31, 2013)	-1,944	-1,174
Total New Source Energy Partners L.P. unitholders' equity	193,894	133,265
Noncontrolling interest	17,420	13,988
Total unitholders' equity	211,314	147,253	0
Total liabilities and unitholders' equity	377,465	254,710
Parent Company [Member]
Current assets:
Cash	1,416	6,027
Accounts receivable, net	15,894	8,645
Derivative contracts	8,248	130
Other current assets	312	109
Total current assets	25,870	14,911
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	332,413	291,829
Less: Accumulated depreciation, depletion, and amortization	-153,734	-128,961
Total oil and natural gas properties, net	178,679	162,868
Property and equipment, net	365	0
Investment in subsidiary	118,185	66,867
Other assets	3,820	3,661
Total assets	326,919	248,307
Current liabilities:
Accounts payable and accrued liabilities	1,975	1,877
Accounts payable-related parties	4,237	7,348
Contingent consideration payable	11,572	0
Derivative contracts	0	3,167
Other current liabilities	113	0
Total current liabilities	17,897	12,392
Long-term debt	83,000	78,500
Contingent consideration payable	10,801	6,320
Asset retirement obligations	3,568	3,455
Other liabilities	339	387
Total liabilities	115,605	101,054
Commitments and contingencies
Unitholders' equity:
Common units (16,160,381 units issued and outstanding at December 31, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	231,510	151,773
Common units held in escrow	-6,955	0
Subordinated units (2,205,000 units issued and outstanding at December 31, 2014 and December 31, 2013)	-28,717	-17,334
General partner's units (155,102 units issued and outstanding at December 31, 2014 and December 31, 2013)	-1,944	-1,174
Total New Source Energy Partners L.P. unitholders' equity	193,894	133,265
Noncontrolling interest	17,420	13,988
Total unitholders' equity	211,314	147,253
Total liabilities and unitholders' equity	$326,919	$248,307

Parent_Company_Financial_Infor4

Parent Company Financial Information - New Source Energy Partners L.P. (Parent Only) - Balance Sheets (Parenthetical) (Details)	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Common units outstanding (in units)	16,160,381	9,599,578
Common units issued (in units)	16,160,381	9,599,578
Subordinated units outstanding (in units)	2,205,000	2,205,000
Subordinated units issued (in units)	2,205,000	2,205,000
General partner's capital units outstanding (in units)	155,102	155,102
General partner's capital units, issued (in units)	155,102	155,102
Parent Company [Member]
Condensed Financial Statements, Captions [Line Items]
Common units outstanding (in units)	16,160,381	9,599,578
Common units issued (in units)	16,160,381	9,599,578
Subordinated units outstanding (in units)	2,205,000	2,205,000
Subordinated units issued (in units)	2,205,000	2,205,000
General partner's capital units outstanding (in units)	155,102	155,102
General partner's capital units, issued (in units)	155,102	155,102

Parent_Company_Financial_Infor5

Parent Company Financial Information - New Source Energy Partners L.P. (Parent Only) - Statement of Operations (Details) (USD $)	1 Months Ended	3 Months Ended																11 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Feb. 12, 2013	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Revenues [Abstract]
Oil sales																			$14,906		$8,090		$5,570
Natural gas sales																			15,534		10,000		6,030
NGL sales																			31,048		28,847		23,996
Total revenues		54,974		56,424		26,818		27,427		18,235		12,431		10,649		9,360			165,643		50,675		35,596
Operating costs and expenses:
Oil, natural gas and NGL production																			18,617		12,631		6,217
Production taxes																			2,833		2,669		1,144
Depreciation, depletion and amortization																			54,352		18,556		14,409
Accretion																			327		209		116
General and administrative																			28,671		14,760	[1]	12,660
Change in fair value of contingent consideration																			-9,031		-1,600		0
Total operating costs and expenses																			215,673		49,265		34,546
Operating (loss) income		-49,217	[2],[3],[4]	-5,075	[2],[3],[4]	1,690	[2],[3],[4]	2,572	[2],[3],[4]	2,951	[5]	2,121	[5]	2,456	[5]	-6,118	[5]		-50,030		1,410		1,050
Other income (expense):
Interest expense																			-5,041		-4,078		-3,202
Gain (loss) on derivative contracts, net		11,500		3,800		-1,400		-3,100		-3,000		-3,500		6,200		-5,300			10,707	[6]	-5,548	[6]	7,057	[6]
Gain on investment in acquired business																			2,298		22,709		0
(Loss) income before income taxes																			-42,075		14,496		4,905
Income tax benefit (expense)		0		0		0		0		0		0		0		-12,126			0		12,126		-1,796
Net loss																		21,319	-42,075		26,622		3,109
Less: net income attributable to noncontrolling interest																			242		0		0
Net (loss) income	5,303	-39,376	[2],[3],[4]	-2,754	[2],[3],[4]	1,586	[2],[3],[4]	-1,531	[2],[3],[4]	21,854	[5]	-1,986	[5]	8,151	[5]	-1,397	[5]	21,319	-42,317		26,622		3,109
Parent Company [Member]
Revenues [Abstract]
Oil sales																			14,906		8,090		5,570
Natural gas sales																			15,534		10,000		6,030
NGL sales																			31,048		28,847		23,996
Total revenues																			61,488		46,937		35,596
Operating costs and expenses:
Oil, natural gas and NGL production																			18,617		12,631		6,217
Production taxes																			2,833		2,669		1,144
Depreciation, depletion and amortization																			24,786		16,590		14,409
Accretion																			327		209		116
General and administrative																			11,051		13,787		12,660
Change in fair value of contingent consideration																			-9,031		-1,600		0
Total operating costs and expenses																			48,583		44,286		34,546
Operating (loss) income																			12,905		2,651		1,050
Other income (expense):
Interest expense																			-3,726		-4,013		-3,202
Gain (loss) on derivative contracts, net																			10,707		-5,548		7,057
Gain on investment in acquired business																			2,298		22,709		0
Loss from subsidiary																			-64,259		-1,303		0
(Loss) income before income taxes																			-42,075		14,496		4,905
Income tax benefit (expense)																			0		12,126		-1,796
Net loss																			-42,075		26,622		3,109
Less: net income attributable to noncontrolling interest																			242		0		0
Net (loss) income																			($42,317)		$26,622		$3,109
[1]	Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.
[2]	Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.
[3]	Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.
[4]	Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.
[5]	Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.
[6]	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.

Parent_Company_Financial_Infor6

Parent Company Financial Information - New Source Energy Partners L.P. (Parent Only) - Statements of Cash Flow (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Cash Flows from Operating Activities:
Net loss	($42,075)		$26,622		$3,109
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	54,352		18,556		14,409
Accretion	327		209		116
Amortization of deferred loan costs	660		479		603
Write off of loan costs due to debt refinancing	167		1,436		0
Equity-based compensation	3,233		7,839		8,204
Deferred income tax benefit	0		-12,024		1,694
Change in fair value of contingent consideration	-9,031		-1,600		0
Gain on investment in acquired business	-2,298		-22,709		0
(Gain) loss on derivative contracts, net	-10,707	[1]	5,548	[1]	-7,057	[1]
Cash (paid) received on settlement of derivative contracts	-1,773		-1,929		5,987
Payments for premiums on derivatives	0		-1,334		0
Changes in operating assets and liabilities:
Accounts receivable	-2,859		-10,595		881
Other current assets and other assets	-4,122		333		0
Accounts payable and accrued liabilities	-547		7,533		-147
Net cash provided by operating activities	44,909		18,364		27,799
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	-63,446		-22,102		0
Additions to oil and natural gas properties	-24,671		-28,921		-12,162
Additions to other property and equipment	-11,536		0		0
Net cash used in investing activities	-99,653		-51,023		-12,162
Cash Flows from Financing Activities:
Proceeds from borrowings	22,369		80,500		3,000
Payments on borrowings	-19,814		-70,102		-3,500
Payments for deferred loan costs	-536		-1,954		-64
Payment on subordinated note payable to parent	0		-25,000		0
Proceeds from sales of common units, net of offering costs	92,375		77,880		0
Proceeds from issuance of common units in private placement, net of offering costs	0		9,833		0
Payments of offering costs	-100		-361		-1,315
Distribution to NSEC	0		-18,295		-13,758
Distribution to unitholders	-36,742		-12,780		0
Net cash provided by (used in) financing activities	52,957		39,950		-15,637
Net change in cash and cash equivalents	-1,787		7,291		0
Cash and cash equivalents, beginning of period	7,291		0		0
Cash and cash equivalents, end of period	5,504		7,291		0
Parent Company [Member]
Cash Flows from Operating Activities:
Net loss	-42,075		26,622		3,109
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Earnings from subsidiaries	64,259		1,303		0
Distributions from subsidiaries	4,406		0		0
Depreciation, depletion and amortization	24,786		16,590		14,409
Accretion	327		209		116
Amortization of deferred loan costs	603		479		603
Write off of loan costs due to debt refinancing	167		1,436		0
Equity-based compensation	644		7,839		8,204
Deferred income tax benefit	0		-12,024		1,694
Change in fair value of contingent consideration	-9,031		-1,600		0
Gain on investment in acquired business	-2,298		-22,709		0
(Gain) loss on derivative contracts, net	-10,707		5,548		-7,057
Cash (paid) received on settlement of derivative contracts	-1,773		-1,929		5,987
Payments for premiums on derivatives	0		-1,334		0
Changes in operating assets and liabilities:
Accounts receivable	1,096		-9,996		881
Other current assets and other assets	-203		256		0
Accounts payable and accrued liabilities	-994		7,617		-147
Net cash provided by operating activities	29,207		18,307		27,799
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	-63,446		-22,102		0
Additions to oil and natural gas properties	-24,671		-28,476		-12,162
Additions to other property and equipment	-378		0		0
Contributions to subsidiaries	-5,000		-1,522		0
Net cash used in investing activities	-93,495		-52,100		-12,162
Cash Flows from Financing Activities:
Proceeds from borrowings	18,750		80,500		3,000
Payments on borrowings	-14,250		-70,000		-3,500
Payments for deferred loan costs	-356		-1,957		-64
Payment on subordinated note payable to parent	0		-25,000		0
Proceeds from sales of common units, net of offering costs	92,375		77,880		0
Proceeds from issuance of common units in private placement, net of offering costs	0		9,833		0
Payments of offering costs	-100		-361		-1,315
Distribution to NSEC	0		-18,295		-13,758
Distribution to unitholders	-36,742		-12,780		0
Net cash provided by (used in) financing activities	59,677		39,820		-15,637
Net change in cash and cash equivalents	-4,611		6,027		0
Cash and cash equivalents, beginning of period	6,027		0		0
Cash and cash equivalents, end of period	$1,416		$6,027		$0
[1]	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.