New Source Energy Partners (NSLP) 10-Q 12 Aug 15 2015 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Aug. 03, 2015
Document Information [Line Items]
Entity Registrant Name	New Source Energy Partners L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Amendment Flag	false
Entity Central Index Key	1,560,443
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Common Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		16,525,736
Subordinated Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		2,205,000

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash	$ 5,734	$ 5,504
Restricted cash	588	350
Accounts receivable, net	14,953	31,919
Accounts receivable-related parties, net	6,712	4,946
Derivative contracts	1,937	8,248
Inventory	3,530	4,236
Prepaid expenses	4,565	2,011
Other current assets	722	478
Total current assets	38,741	57,692
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	333,196	332,413
Less: Accumulated depreciation, depletion, amortization, and impairment	(237,981)	(153,734)
Total oil and natural gas properties, net	95,215	178,679
Property and equipment, net	68,418	68,886
Intangible assets, net	0	56,377
Goodwill	0	9,315
Derivative contracts	3	1,818
Other assets	2,381	2,779
Total assets	204,758	375,546
Current liabilities:
Accounts payable and accrued liabilities	17,999	15,326
Accounts payable-related parties	1,346	2,318
Factoring payable	5,098	13,152
Contingent consideration payable	21,968	11,572
Current portion of long-term debt	19,458	11,825
Other current liabilities	117	113
Total current liabilities	65,986	54,306
Long-term debt	49,602	95,218
Series A Cumulative Convertible Redeemable Preferred Units (1,930,000 units issued and outstanding at June 30, 2015)	44,629	0
Contingent consideration payable	0	10,801
Asset retirement obligations	3,697	3,568
Other liabilities	237	339
Total liabilities	$ 119,522	$ 164,232
Commitments and contingencies (Note 14)
Unitholders' equity:
Common units (16,525,736 units issued and outstanding at June 30, 2015 and 16,160,381 units issued and outstanding at December 31, 2014)	$ 76,291	$ 231,510
Common units held in escrow	(3,734)	(6,955)
Subordinated units (2,205,000 units issued and outstanding at June 30, 2015 and December 31, 2014)	(49,370)	(28,717)
General partner's units (none issued and outstanding at June 30, 2015 and 155,102 units issued and outstanding at December 31, 2014)	0	(1,944)
Total New Source Energy Partners L.P. unitholders' equity	23,187	193,894
Noncontrolling interest	17,420	17,420
Total unitholders' equity	40,607	211,314
Total liabilities, redeemable preferred units and unitholders' equity	$ 204,758	$ 375,546

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Unaudited) (Parentheticals) - shares	Jun. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common units outstanding (in Shares)	16,525,736	16,160,381
Common units issued (in Shares)	16,525,736	16,160,381
Subordinated units outstanding (in Shares)	2,205,000	2,205,000
Subordinated units issued (in Shares)	2,205,000	2,205,000
General partner's capital units outstanding (in Shares)	0	155,102
General partner's capital units, issued (in Shares)	0	155,102
Series A preferred units, shares issued (in Shares)	1,930,000
Series A preferred units, shares issued (in Shares)	1,930,000

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Oil sales	$ 1,648	$ 4,402	$ 3,340	$ 8,348
Natural gas sales	1,404	3,850	3,247	9,217
NGL sales	2,267	8,466	5,299	18,004
Oilfield services	18,765	10,100	50,315	18,676
Total revenues	24,084	26,818	62,201	54,245
Operating costs and expenses:
Oil, natural gas and NGL production	3,810	4,516	7,865	9,019
Production taxes	282	792	593	1,671
Cost of providing oilfield services	14,637	5,968	37,696	10,534
Depreciation, depletion and amortization	5,999	10,289	18,346	19,567
Accretion	59	74	133	143
Impairment	99,689	0	142,808	0
General and administrative	6,671	3,489	18,905	9,050
Total operating costs and expenses	131,147	25,128	226,346	49,984
Operating (loss) income	(107,063)	1,690	(164,145)	4,261
Other income (expense):
Interest expense	(1,749)	(1,015)	(3,097)	(1,984)
(Loss) gain on derivative contracts, net	(1,067)	(1,396)	157	(4,528)
Gain on investment in acquired business	0	2,298	0	2,298
Other income	23	9	57	7
Net (loss) income	(109,856)	1,586	(167,028)	54
Less: net income attributable to noncontrolling interest	0	0	0	0
Net (loss) income attributable to New Source Energy Partners L.P.	(109,856)	1,586	(167,028)	54
distributions on Series A Preferred Units	988	0	988	0
accretion of discount on Series A Preferred Units	175	0	175	0
Net (loss) income attributable to New Source Energy Partners L.P. common, subordinated and general partner units	$ (111,019)	$ 1,586	(168,191)	$ 54
General Partnership Units [Member]
Other income (expense):
Net (loss) income			$ (470)
Net (loss) income - per unit:
Basic and diluted income per unit (in usd per unit)	$ 0	$ 0.11	$ (3.03)	$ (0.02)
Subordinated Units [Member]
Other income (expense):
Net (loss) income			$ (20,515)
Net (loss) income - per unit:
Basic and diluted income per unit (in usd per unit)	(6.12)	0.11	$ (9.37)	(0.02)
Common Units [Member]
Other income (expense):
Net (loss) income			$ (146,043)
Net (loss) income - per unit:
Basic and diluted income per unit (in usd per unit)	$ (5.92)	$ 0.11	$ (8.97)	$ 0.01

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Unitholders' Equity (Unaudited) - 6 months ended Jun. 30, 2015 - USD ($) $ in Thousands	Total	Common [Member]	Subordinated [Member]	General Partnership [Member]	Noncontrolling Interest [Member]
Beginning Balance (in units) at Dec. 31, 2014		16,160,381	2,205,000	155,102
Beginning Balance at Dec. 31, 2014	$ 211,314	$ 224,555	$ (28,717)	$ (1,944)	$ 17,420
Increase (Decrease) in Partners' Capital [Roll Forward]
Acquisition from unitholder	(227)	$ (227)
Equity-based compensation (in units)		210,253
Equity-based compensation	4,322	$ 4,322
Distributions to unitholders	(6,611)	$ (6,580)		$ (31)
General partner unit conversion to common units (in units)		155,102		(155,102)
General partner unit conversion to common units		$ (2,445)		$ 2,445
Distributions on Series A Preferred Units	(988)	(871)
Accretion of discount on Series A Preferred Units	(175)	(154)
Net loss	(167,028)	$ (146,043)	$ (20,515)	$ (470)
Ending Balance (in units) at Jun. 30, 2015		16,525,736	2,205,000	0
Ending Balance at Jun. 30, 2015	$ 40,607	$ 72,557	$ (49,370)	$ 0	$ 17,420

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Cash Flow (Unaudited) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014
Cash Flows from Operating Activities:
Net (loss) income		$ (167,028)	$ 54
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		18,346	19,567
Impairment		142,808	0
Accretion		133	143
Amortization of deferred loan costs		619	292
Write-off of deferred loan costs		332	0
Equity-based compensation		4,322	644
Change in fair value of contingent consideration		0	(912)
Gain on investment in acquired business		0	(2,298)
(Gain) loss on derivative contracts, net		(157)	4,528
Cash received (paid) on settlement of derivative contracts	[1]	8,339	(3,412)
Changes in operating assets and liabilities:
Accounts receivable		15,121	(3,045)
Inventory		(2,351)	0
Other current assets and other assets		(836)	(1,493)
Accounts payable and accrued liabilities		(3,094)	620
Net cash provided by operating activities		16,554	14,688
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired		0	(63,446)
Additions to oil and natural gas properties		(941)	(18,218)
Additions to other property and equipment		(5,380)	(2,991)
Net cash used in investing activities		(6,321)	(84,655)
Cash Flows from Financing Activities:
Proceeds from issuance of Series A Preferred Units, net		44,454	0
Proceeds from borrowings		9,163	14,934
Payments on borrowings		(48,575)	(5,648)
Deposit for financing insurance		(380)	0
Bank overdraft		0	1,838
Proceeds from financing		0	808
Proceeds from borrowings, net - related party		0	300
Payments for deferred loan costs		0	(437)
Payments on factoring payable, net		(8,054)	(1,583)
Proceeds from sales of common units, net of offering costs		0	76,191
Payments of offering costs		0	(100)
Distribution to unitholders		(6,611)	(15,259)
Net cash (used in) provided by financing activities		(10,003)	71,044
Net change in cash and cash equivalents		230	1,077
Cash and cash equivalents, beginning of period		5,504	7,291
Cash and cash equivalents, end of period		5,734	8,368
Supplemental Cash Flow Information:
Cash paid for interest		2,105	1,859
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation		0	189
Decrease in accrued capital expenditures		(936)	(1,457)
Common units issued in connection with acquisitions		0	(46,239)
Factoring payables assumed in connection with acquisitions		0	15,840
Acquisition of property and equipment by financing		1,200	2,725
Distributions payable on Series A Preferred Units		988	0
Accretion of discount on Series A Preferred Units		175	0
Debt assumed in connection with acquisitions		$ 0	$ 17,571
[1]	Cash receipts upon settlement of derivative contracts for the three and six months ended June 30, 2015 includes $3.9 million related to the settlement of certain derivative contracts with contract maturities subsequent to the period in which they were settled ("early settlements"). In the second quarter of 2015, we monetized certain of our derivative contracts for the periods October 2015 through December 2015 and calendar year 2016.

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation Nature of Business. We are a Delaware limited partnership formed in October 2012 to own and acquire oil and natural gas properties in the United States. We are engaged in the production of onshore oil and natural gas properties that extend across conventional resource reservoirs in east-central Oklahoma. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation. In addition, we are engaged in oilfield services through our oilfield services subsidiaries. Our oilfield services business provides wellsite services during the drilling and completion stages of a well, including full service blowout prevention installation, pressure testing services, including certain ancillary equipment necessary to perform such services, well testing and flowback services to companies in the oil and natural gas industry primarily in Oklahoma, Texas, New Mexico, Kansas, Pennsylvania, Ohio and West Virginia. Principles of Consolidation. The unaudited condensed consolidated financial statements include the accounts of the Partnership and its wholly owned and majority owned subsidiaries. Noncontrolling interest represents third-party ownership interest in a majority owned subsidiary of the Partnership and is included as a component of equity in the consolidated balance sheet and consolidated statement of unitholders' equity. All significant intercompany accounts and transactions have been eliminated in consolidation. Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2014 have been derived from the audited financial statements contained in the Partnership’s 2014 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2014 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s accompanying unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2014 Form 10-K. Significant Accounting Policies. For a description of the Partnership’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2014 Form 10-K. Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Partnership's previously reported results of operations. Use of Estimates. The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed and asset retirement obligations. Actual results could differ from those estimates. Liquidity . As shown in the accompanying financial statements, the Partnership has incurred losses and has a working capital deficit at June 30, 2015. The Partnership anticipates it will continue to generate losses from operations and that cash flows may not be sufficient to cover its operating expenses, capital needs or additional debt payments resulting from the violation of debt covenants. The Partnership's ability to continue as a going concern depends on its ability to execute its business plan. However, our current cash position and our ability to access additional capital may limit our available opportunities and may not provide sufficient cash for operations, capital requirements or debt service. As we have violated debt covenants on certain of our oilfield service related debt, as discussed in Note 3 "Debt," it is possible that we will have to pay amounts outstanding sooner than anticipated based on the original maturity. Additionally, we anticipate that the borrowing base on our senior secured revolving credit facility (the "credit facility") will be further reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management is actively pursuing additional sources of capital. We believe that we will be successful in securing any funds necessary to continue as a going concern. The Partnership, however, is dependent upon its ability to secure equity or debt financing or monetize certain of its oilfield services assets and there are no assurances that the Partnership will be successful in such endeavors. The financial statements do not include any adjustments that might result from the outcome of any uncertainty as to the Partnership’s ability to continue as a going concern. The financial statements also do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classifications of liabilities that might be necessary should the Partnership be unable to continue as a going concern. Recently Issued Accounting Standards. 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 was originally effective for fiscal years beginning after December 15, 2016. In July 2015, the FASB voted to approve a one-year deferral of the effective date of ASU 2014-09. 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, if any, the guidance will have on our related disclosures. In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction from the carrying amount of the related debt. The new standard does not change the recognition and measurement of debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. Upon adoption of the guidance, assets and liabilities will decrease in the consolidated balance sheet with no impact to the consolidated statement of operations. In April 2015, the FASB issued ASU No. 2015-06, “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a consensus of the FASB Emerging Issues Task Force),” which applies to master limited partnerships that receive net assets through a dropdown transaction. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. ASU 2015-06 is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years and will be applied retrospectively. Earlier application is permitted. We are currently evaluating the effect, if any, this updated standard will have.

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions The Partnership completed acquisitions during 2014, as described below. The acquisitions of Erick Flowback Services LLC ("EFS"), Rod's Production Services, L.L.C. ("RPS") and MidCentral Completion Services, LLC ("MCCS") expanded the Partnership's oilfield services segment. The acquisition of MCCS was with related parties. See Note 11 "Related Party Transactions." In 2014, we also acquired working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma to expand the Partnership's exploration and production segment. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy as described in Note 6 "Fair Value Measurements." Fair value may be estimated using comparable market data, a discounted cash flow method, or another method as discussed below. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of applicable sales estimates, operational costs and a risk-adjusted discount rate. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. Fair value of MCCS' inventory acquired was determined based on a comparative sales approach. Fair value for intangible assets acquired was primarily determined using a discounted cash flow model or multi-period excess earnings model under the income approach, which factors in discount rates, probability factors and forecasts. The fair values of property, plant and equipment acquired were primarily based on a cost approach using an indirect cost methodology to determine replacement cost. The inputs, as noted above, used to determine fair value required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Carrying value for current assets and liabilities acquired is typically representative of fair value due to their short term nature. CEU Acquisition. On January 31, 2014, we completed the acquisition of working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma, from CEU Paradigm, LLC ("CEU") for approximately $17.1 million , net of purchase price adjustments (the "CEU Acquisition"). The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition, net of purchase price adjustments, is as follows (in thousands): Consideration: Cash $ 5,503 Fair value of common units granted (1) 11,621 Contingent consideration (2) — Total fair value of consideration $ 17,124 Fair value of assets acquired and liabilities assumed: Proved oil and natural gas properties $ 17,306 Asset retirement obligations (182 ) Total net assets $ 17,124 __________ (1) The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition). (2) The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU. MCCS Acquisition. On June 26, 2014, we exercised the option granted in connection with the acquisition of MCE in November 2013 to acquire 100% of the equity interest in MCCS, an oilfield services company that specializes in providing services, primarily installation and pressure testing, to oil and natural gas exploration and production companies (the "MCCS Acquisition"). Total consideration for the MCCS Acquisition is as follows (in thousands): Consideration: Fair value of common units granted (1) $ 789 Contingent consideration (2) 4,057 Noncontrolling interest (3) 831 Total fair value of consideration $ 5,677 __________ (1) The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition). (2) The Partnership agreed to provide additional common units in the second quarter of 2015 to the former owners of MCCS based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended 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 14 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration. (3) As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation. The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands): Fair value of assets acquired and liabilities assumed: Cash $ 109 Accounts receivable 524 Inventory 2,035 Other current assets 14 Property and equipment 107 Intangible asset (1) 1,700 Goodwill (2) 3,382 Other assets 28 Total assets acquired 7,899 Accounts payable and accrued liabilities (1,431 ) Long-term debt (791 ) Total liabilities assumed (2,222 ) Net assets acquired $ 5,677 __________ (1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years . (2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS' business. Since the Chairman and Chief Executive Officer of our general partner, Mr. Kos, through his control over our general partner, controls the Partnership and also owned 50% of the equity interest in MCCS, the MCCS Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 50% equity interest in MCCS acquired from Mr. Kos at his equity method carrying basis, which was $0.1 million as of June 26, 2014. The Partnership remeasured the 50% interest to determine the acquisition-date fair value and recognized a corresponding gain of $2.3 million on investment in acquired business. Services Acquisition. On June 26, 2014, the Partnership acquired 100% of the outstanding membership interests in EFS and 100% of the outstanding membership interests in RPS for total consideration of approximately $113.2 million (the "Services Acquisition"). EFS and RPS, which are affiliated entities, are oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry. Total consideration for the Services Acquisition is as follows (in thousands): Consideration: Cash $ 57,348 Fair value of common units granted (1) 33,106 Common units granted for the benefit of EFS and RPS employees (2) 724 Contingent consideration (3) 21,984 Total fair value of consideration $ 113,162 __________ (1) The fair value of the unit consideration was based upon 1,411,777 common units valued at $23.45 per unit (closing price on the date of the acquisition). (2) The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 8 "Equity" for additional discussion of phantom units. (3) The Partnership agreed to provide additional consideration in the second quarter of 2015 to the former owners of EFS and RPS 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 at the acquisition date through the use of a probability analysis. See Note 14 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration. The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands): Fair value of assets acquired and liabilities assumed: Cash $ 1,668 Accounts receivable 22,674 Other current assets 620 Property and equipment 43,853 Intangible assets (1) 68,700 Goodwill (2) 14,224 Total assets acquired 151,739 Accounts payable and accrued liabilities (5,937 ) Factoring payable (15,840 ) Long-term debt (16,800 ) Total liabilities assumed (38,577 ) Net assets acquired $ 113,162 __________ (1) Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years . Non-compete agreements were valued based on an income approach and are amortized over the agreement period. (2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS and RPS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships. Goodwill has been allocated to the oilfield services segment. Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the three and six months ended June 30, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the three and six months ended June 30, 2014 have been prepared by adjusting the historical results of the Partnership to include the historical results of the 2014 Material Acquisitions through the dates of acquisition and estimates of the effect of these transactions on the combined results. In addition, pro forma adjustments have been made assuming the units issued as consideration for these acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund the Services Acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. Three Months Ended June 30, 2014 Six Months Ended June 30, 2014 (in thousands, except per unit amounts) Revenue $ 55,881 $ 116,166 Net income attributable to New Source Energy Partners L.P. (1) $ 4,079 $ 6,186 Net income per common unit (1): Basic $ 0.24 $ 0.37 Diluted $ 0.24 $ 0.37 __________ (1) Excludes $23.9 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 amount of revenues and operating income included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 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 revenues 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 and other taxes for the CEU Acquisition. Three Months Ended June 30, 2014 Six Months Ended June 30, 2014 (in thousands) Revenue $ 3,054 $ 4,937 Excess of revenue over direct operating expenses $ 1,077 $ 2,196 Acquisition expense for the 2014 Material Acquisitions of $1.3 million was included in general and administrative expenses in the accompanying unaudited statements of operations for both the three and six months ended June 30, 2014.

Debt

Debt	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Debt	Debt The Partnership's debt consists of the following (in thousands): June 30, 2015 December 31, 2014 Credit facility $ 49,000 $ 83,000 Notes payable 17,693 20,424 Line of credit 2,367 3,619 Total debt 69,060 107,043 Less: current maturities of long-term debt 19,458 11,825 Long-term debt $ 49,602 $ 95,218 Senior Secured Revolving Credit Facility The Partnership has a credit facility that is available to be drawn on subject to limitations based on its terms and certain financial covenants described below. As of June 30, 2015 , the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0 ; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0 ; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0 , in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of its subsidiaries. The credit facility matures in February 2017 . In the second quarter of 2015, the credit facility was amended to, among other things, provide for 2100 Energy’s acquisition of a portion of Deylau's limited liability company interest in our general partner in April 2015, which is discussed further in Note 11 "Related Party Transactions," increase certain of the collateral requirements, permit us to dispose all of our limited liability company interest in MCE GP upon the satisfaction of various conditions as described in Note 11 "Related Party Transactions," permit the Partnership to make cash distributions up to $6.0 million per year to holders of our Series A Preferred Units and impose certain hedging requirements for our oil and natural gas assets upon our unwinding of any current hedges prior to the October 2015 redetermination date. 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. 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 June 30, 2015 , the Partnership was in compliance with all covenants under the credit facility. Our credit facility is subject to a borrowing base which is generally set by the bank semi-annually on April 1 and October 1 of each year. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. In the second quarter of 2015, our borrowing base was lowered from $90.0 million to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. On May 29, 2015, the borrowing base was reduced further to $57.0 million in response to the settlement of a portion of our derivative contracts prior to their contractual maturity. We anticipate that our borrowing base will be reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. As of June 30, 2015 , the Partnership had $49.0 million in outstanding borrowings with $8.0 million of available borrowing capacity. 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 June 30, 2015 and December 31, 2014 , the average annual interest rate on borrowings outstanding under the credit facility was 3.19% and 3.44% , respectively. Notes Payable MCES Notes Payable. The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. The notes range from 12 to 60 months in duration with maturity dates from August 2015 through March 2019 and carry variable interest rates ranging from 5.50% to 10.51% . All notes are associated with specific capital assets of MCES and are secured by such assets. Certain of these notes contain a requirement for MCES to maintain a fixed charge ratio of not less than 1.25 to 1.0 . As of June 30, 2015 , MCES was not in compliance with the covenants under certain of these notes and, as such, is in default on these notes. As a result, the outstanding balances for these notes were reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. The Partnership had $5.5 million outstanding, of which $4.9 million was current, under the MCES notes payable as of June 30, 2015 . EFS Loan Agreement. In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on EFS' existing notes payable, which were originally set to mature on June 26, 2015 . In March 2015, we refinanced EFS' notes payable to extend the maturity date to March 2018 . The balance on the note payable at June 30, 2015 was $10.8 million . The note payable has a variable interest rate based on the Bank 7 Base Rate minus 2.3% with a minimum and initial interest rate of 5.5% . The effective rate was 5.5% at June 30, 2015 . Payments of principal and interest are due in monthly installments. The note payable is collateralized by various assets of the parties to the agreement and guaranteed by MCE. The Partnership is required to maintain a reserve bank account into which $0.3 million shall be deposited quarterly beginning after the initial deposit of $0.5 million on September 30, 2015, and used to fund an additional annual payment on September 30th of each year during the term of the note. The EFS loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0 , (ii) a leverage ratio of not greater than 1.5 to 1.0 , and (iii) a working capital and cash balance of at least $1.0 million by June 30, 2015 increasing to at least $3.5 million by October 1, 2015, in each case as more fully described in the loan agreement. As of June 30, 2015 , EFS and RPS was in default as we were not in compliance with the covenants under the loan agreement. As a result, the outstanding balance was reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. MCES Promissory Notes . On January 9, 2015 and February 24, 2015, MCES issued promissory notes totaling approximately $1.4 million , to acquire land from entities owned 50% by Mr. Kos and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner. Both promissory notes bear interest at prime plus one percent and are payable, including all accrued interest, on December 31, 2015. No payments are due prior to maturity. See Note 11 "Related Party Transactions" for additional discussion of the related party land transactions. Line of Credit In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million , based on a borrowing base of $4.0 million related to MCES' accounts receivable. In June 2015, the line of credit was lowered to a maximum of $3.0 million with the borrowing base determined based on MCES' eligible accounts receivable. Our monthly interest only payments accrue at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at June 30, 2015 . The line of credit matures in September 2015 and is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. The outstanding balance was $2.4 million at June 30, 2015 and was reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. The line of credit contains a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0 . As of June 30, 2015 , MCES was not in compliance with this covenant under the line of credit, which is considered an event of default under the terms of the agreement.

Factoring Payable

Factoring Payable	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Factoring Payable	Factoring Payable The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of MCES. The outstanding balance was paid and the agreement was terminated in February 2014 when MCES established its line of credit. See Note 3 "Debt" for discussion of MCES' line of credit. In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 3% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not collected within 90 days , the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $5.1 million as of June 30, 2015 .

Derivative Contracts

Derivative Contracts	6 Months Ended
	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Contracts	Derivative Contracts Due to the volatility of commodity prices, the Partnership periodically enters into derivative contracts for a portion of its oil, natural gas and NGL production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of derivative contracts limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and NGLs, it also reduces the Partnership’s potential exposure to adverse price movements. The Partnership’s derivative contracts apply to only a portion of its expected production, provide only partial price protection against declines in market prices and limit the Partnership’s potential gains from future increases in market prices. Changes in the derivatives' fair values are recognized in earnings since the Partnership has elected not to designate its derivative contracts as hedges for accounting purposes. At June 30, 2015 , the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below: Collars The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party. Collars - three way Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract. Put options The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the market price and the fixed price. Fixed price swaps The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. The following tables present our derivative instruments outstanding as of June 30, 2015 : Oil collars Volumes Floor Price Ceiling Price July 2015 - September 2015 9,317 $ 80.00 $ 93.25 October 2015 - December 2015 26,220 $ 55.00 $ 67.00 January 2016 - March 2016 25,935 $ 55.00 $ 67.00 April 2016 - December 2016 45,375 $ 55.00 $ 69.20 Oil collars - three way Volumes Sold Put Purchased Put Ceiling Price July 2015 - December 2015 9,200 $ 77.50 $ 92.50 $ 102.60 Oil fixed price swaps Volumes (Bbls) Weighted Average Fixed Price July 2015 - September 2015 10,777 $ 88.90 Natural gas collars Volumes Floor Price Ceiling Price July 2015 - September 2015 325,114 $ 4.00 $ 4.32 October 2015 - December 2015 340,400 $ 2.85 $ 3.46 January 2016 - March 2016 336,700 $ 2.85 $ 3.46 April 2016 - December 2016 1,017,500 $ 2.85 $ 3.40 Natural gas put options Volumes (MMBtu) Floor Price July 2015 - December 2015 210,876 $ 3.50 Natural gas fixed price swaps Volumes (MMBtu) Weighted Average Fixed Price July 2015 - September 2015 194,461 $ 4.25 NGL fixed price swaps Volumes Weighted Average Fixed Price July 2015 - September 2015 20,782 $ 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 tables summarize our derivative contracts on a gross basis and the effects of netting assets and liabilities for which the right of offset exists (in thousands): June 30, 2015 Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset Net Amounts Presented Assets: Commodity derivatives - current assets $ 1,942 $ (5 ) $ 1,937 Commodity derivatives - long-term assets 3 — 3 Total $ 1,945 $ (5 ) $ 1,940 Liabilities: Commodity derivatives - current liabilities $ (5 ) $ 5 $ — Commodity derivatives - long-term liabilities (1) (56 ) — (56 ) Total $ (61 ) $ 5 $ (56 ) __________ (1) Commodity derivatives - long-term liabilities are included in other liabilities on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. December 31, 2014 Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset Net Amounts Presented Assets: Commodity derivatives - current assets $ 8,309 $ (61 ) $ 8,248 Commodity derivatives - long-term assets 1,818 — 1,818 Total $ 10,127 $ (61 ) $ 10,066 Liabilities: Commodity derivatives - current liabilities $ 61 $ (61 ) $ — Commodity derivatives - long-term liabilities — — — Total $ 61 $ (61 ) $ — See Note 6 "Fair Value Measurements" for additional information on the fair value measurement of the Partnership's derivative contracts. The following table presents cash settlements on our derivative contracts as included in (loss) gain on derivative contracts, net in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Cash receipts (payments) upon settlement (1) $ 6,000 $ (983 ) $ 8,339 $ (3,412 ) __________ (1) Cash receipts upon settlement of derivative contracts for the three and six months ended June 30, 2015 includes $3.9 million related to the settlement of certain derivative contracts with contract maturities subsequent to the period in which they were settled ("early settlements"). In the second quarter of 2015, we monetized certain of our derivative contracts for the periods October 2015 through December 2015 and calendar year 2016.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements We measure and report certain assets and liabilities at fair value and classify and disclose our fair value measurements based on the levels of the fair value hierarchy, as described below: Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership's assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Level 2 Fair Value Measurements Derivative contracts. The fair values of our commodity collars, put options and fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. The Partnership estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. The Partnership validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. The Partnership estimates the option value of puts and calls combined into hedges, market prices, contract parameters and discount rates based on published LIBOR rates. Level 3 Fair Value Measurements Derivative contracts. The fair values of our natural gas collars, natural gas and NGL put options and NGL fixed price swaps prior to the second quarter of 2014 were based upon quotes obtained from counterparties to the derivative contracts. See discussion below regarding transfer of these derivative contracts from Level 3 to Level 2. 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 14 "Commitments and Contingencies," the Partnership agreed to pay additional consideration on certain acquisitions if specific target metrics were met. The fair value of the contingent consideration resulting from these acquisitions was 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 result in a significantly higher (lower) fair value measurement. The following tables set 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): June 30, 2015 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 $ — $ 667 $ — $ 667 Natural gas put options — 140 — 140 Oil, natural gas and NGL fixed price swaps — 1,077 — 1,077 Total $ — $ 1,884 $ — $ 1,884 December 31, 2014 Fair Value Measurements Description Active Markets for Identical Assets (Level 1) Observable Inputs (Level 2) Unobservable Inputs (Level 3) Total Carrying Value Oil and natural gas collars $ — $ 2,411 $ — $ 2,411 Oil, natural gas and NGL put options — 1,405 — 1,405 Oil, natural gas and NGL fixed price swaps — 6,250 — 6,250 Contingent consideration — — (23,330 ) (23,330 ) Total $ — $ 10,066 $ (23,330 ) $ (13,264 ) The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six months ended June 30, 2014 (in thousands): Three Months Ended Six Months Ended Beginning balance $ (2,843 ) $ (2,517 ) Loss on derivative contracts — (2,432 ) Transfers out (1) 2,843 2,843 Cash received upon settlement — 2,106 Ending balance (1) $ — $ — Unrealized losses included in earnings relating to derivatives held at period end $ — $ — __________ (1) Fair values related to the Company’s natural gas collars, natural gas and NGL put options and NGL fixed price swaps were transferred from Level 3 to Level 2 in the second quarter of 2014 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. See Note 5 "Derivative Contracts" for additional discussion of our derivative contracts. Fair Value of Financial Instruments Credit Facility. The carrying amount of the credit facility of $49.0 million and $83.0 million as of June 30, 2015 and December 31, 2014 , respectively, approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings. Notes Payable . The carrying value of our notes payable of $17.7 million and $20.4 million at June 30, 2015 and December 31, 2014 approximated fair value based on rates applicable to similar instruments. The credit facility and notes payable are classified as a Level 2 item within the fair value hierarchy. Fair Value on a Non-Recurring Basis The Partnership performs valuations on a non-recurring basis primarily as it relates to the consideration, assets acquired and liabilities assumed related to acquisitions and, as required, for impairment analysis of goodwill, intangible assets and property, plant and equipment. See Note 2 "Acquisitions," Note 7 "Goodwill and Intangible Assets," Note 12 "Property, Plant and Equipment" and Note 14 "Commitments and Contingencies" for discussion of these valuations.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	6 Months Ended
	Jun. 30, 2015
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. A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands): Goodwill at December 31, 2014 $ 9,315 Impairment (9,315 ) Goodwill at June 30, 2015 $ — The goodwill balance as of December 31, 2014 is associated with the acquisition of EFS. As of April 1, 2015, the Partnership performed the annual impairment test on goodwill. Primarily as a result of a decrease in projected revenue of EFS, which is a significant component in determining the fair value of this reporting unit, the carrying value of EFS exceeded its fair value. We performed step two of the impairment test to determine the amount of goodwill that was impaired. Based on this assessment, it was determined that goodwill was fully impaired and $9.3 million was recorded as impairment and included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015. Intangible Assets. Intangible assets were identified in the acquisitions during 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 for the non-compete agreements. Amortization expense for the six months ended June 30, 2015 was $ 5.2 million . There was no amortization expense for the three months ended June 30, 2015 as a result of the impairment of our intangible assets, as discussed below. Amortization expense for the three and six months ended June 30, 2014 was $ 3.1 million and $ 6.2 million , respectively. A reconciliation of the Partnership's intangible assets for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands): Intangible assets, net, at December 31, 2014 $ 56,377 Amortization expense (5,166 ) Impairment (51,211 ) Intangible assets, net, at June 30, 2015 $ — In the second quarter of 2015, the Partnership deemed the continued 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 less than the respective revenue generating asset groups' carrying value for the intangible assets from the Services Acquisition. Based on the discounted cash flows of the asset group, an impairment of these intangible assets, or approximately $51.2 million , was recorded and is included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015.

Equity

Equity	6 Months Ended
	Jun. 30, 2015
Equity [Abstract]
Equity	Equity Equity Offerings Issuance for Acquisitions. In 2014, we issued 1,964,957 of common units to satisfy the equity portion of the consideration paid in the CEU Acquisition, the MCCS Acquisition, and the Services Acquisition. See Note 2 "Acquisitions" for additional discussion of these transactions. Equity Offering. In April 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million . We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes. On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. We also granted the underwriters a 30 -day overallotment option to purchase up to an additional 264,000 Series A Preferred Units. On June 5, 2015, the underwriters partially exercised the overallotment option and we issued an additional 170,000 Series A Preferred Units for approximately $4.0 million in additional proceeds. See Note 9 "Cumulative Convertible Preferred Units" for further discussion of our Series A Preferred Units. Distributions Distributions are declared and distributed within 45 days following the end of each quarter. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the six months ended June 30, 2015 and 2014 , are shown in the following table (in thousands, except per unit amounts): Distributions Declaration Date Payable Date Distribution per Unit Common Units Subordinated Units General Partner Units Total 2015 First Quarter May 8, 2015 May 15, 2015 $ 0.20 $ 3,312 $ — $ — $ 3,312 Second Quarter N/A N/A $ — $ — $ — $ — $ — 2014 First Quarter April 21, 2014 May 15, 2014 $ 0.580 $ 7,852 $ 1,279 $ 90 $ 9,221 Second Quarter July 21, 2014 August 15, 2014 $ 0.585 $ 9,025 $ 1,290 $ 91 $ 10,406 Pursuant to our partnership agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. No such incentive distributions were made to our general partner as quarterly distributions declared by the board of directors for the first or second quarters of 2015 and 2014 did not exceed the specified targets. We suspended common unit distributions in July 2015 for the second quarter of 2015 and made distributions per common unit of $0.20 in the first quarter of 2015. These distributions were below the minimum quarterly distribution ("MQD") established by our partnership agreement. Subordinated units are not entitled to receive distributions until the common units receive an amount equal to the MQD and the cumulative arrearages of approximately $14.0 million at June 30, 2015. The subordination period ends on the first business day after all units have received the MQD for each of four consecutive quarters ending on or after December 31, 2015, or as otherwise provided for under the partnership agreement. Noncontrolling Interest As part of the MCE Acquisition, certain former owners of MCE retained 100 Class B Units in MCE. The MCE partnership agreement provides that the Class B Units have the right to receive an increasing percentage ( 15% , 25% and 50% ) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved based on the results of MCES and MCCS. Target distribution levels are adjusted, as applicable and in accordance with the MCE partnership agreement, under certain circumstances. As these Class B Units are not held by the Partnership, they are presented as noncontrolling interest in the accompanying unaudited condensed consolidated financial statements. Any distribution to the Class B Units will be recognized in the period earned and recorded as a reduction to net income attributable to the Partnership. As a result of the MCCS Acquisition, the specified target distribution levels for the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders were adjusted for the contribution of MCCS to MCE by the Partnership as provided for in the MCE partnership agreement. The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels, as adjusted based on the MCCS Acquisition. Marginal Percentage Interest in Total Quarterly Distributions per MCE Unit MCE Class A Unitholders (the Partnership) MCE Class B Unitholders Minimum Quarterly Distribution $16,116 100% —% First Target Distribution $18,533 to $20,144 85% 15% Second Target Distribution $20,145 to $24,173 75% 25% Third Target Distribution and Thereafter $24,174 and above 50% 50% No distributions were due to the MCE Class B unitholders for the first six months of 2015 or 2014. Equity Compensation We may grant awards of the Partnership's common units to employees under the Partnership's Long-Term Incentive Plan ("LTIP") or Fair Market Value Purchase Plan ("FMVPP"). In the first quarter of 2015, we granted 242,753 common units under the LTIP. Of these common units granted, 219,439 vested immediately or had accelerated vesting, which resulted in $1.5 million of equity-based compensation expense and is included in the accompanying unaudited condensed consolidated statement of operations for the six months ended June 30, 2015. Phantom Units . In conjunction with the Services Acquisition, the Partnership granted 432,038 phantom units, which represent the right to receive common units or cash equal to the value of the associated common units, to employees of EFS and RPS under the FMVPP. The phantom units vest over a period not to exceed 2 years . Although the phantom unit grants may be settled in either common units or cash at the holder's election, the settlement of the phantom units upon vesting will be made from a transfer or sale of the associated common units that were issued to an escrow account, reflected as contra equity on the accompanying unaudited condensed consolidated balance sheets, in conjunction with the Services Acquisition. As a result, the 401,171 phantom units valued at $10.1 million with a service requirement were measured at fair market value of the Partnership’s common units on the grant date and are being expensed over the vesting period in accordance with accounting guidance for equity compensation. In the first quarter of 2015, the vesting of certain phantom unit awards was accelerated resulting in $0.9 million of expense. There were no accelerated vestings in the second quarter of 2015. For the three and six months ended June 30, 2015 , the Partnership recorded total equity-based compensation expense of $0.4 million and $4.3 million , respectively, compared to $0.4 million and $0.6 million for the same periods in 2014. Equity-based compensation expense for the 2015 period includes amounts related to awards granted in the second half of 2014 and first quarter of 2015, including amounts for awards in which vesting was accelerated.

Cumulative Convertible Preferre

Cumulative Convertible Preferred Units	6 Months Ended
	Jun. 30, 2015
Temporary Equity Disclosure [Abstract]
Cumulative Convertible Preferred Units	Preferred Units On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. In addition, we granted the underwriters a 30 -day overallotment option to purchase up to an additional 264,000 Series A Preferred Units. On June 5, 2015, the underwriters partially exercised the overallotment option and purchased an additional 170,000 Series A Preferred Units. Holders of our Series A Preferred Units are entitled to receive quarterly cash distributions at the rate of 11.0% per annum. The Series A Preferred Units are convertible into common units on any January 1, April 1, July 1 or October 1 by the holder at the initial conversion rate of 3.7821 common units per Series A Preferred Unit. We may elect to convert the Series A Preferred Units into our common units on or after July 15, 2018 in certain circumstances. We will redeem all of the Series A Preferred Units on July 15, 2022 at a redemption price equal to the liquidation preference of $25.00 plus an amount equal to accumulated but unpaid distributions thereon. If we do not redeem the Series A Preferred Units on July 15, 2022, then the per annum distribution rate will increase by an additional 2.0% per month until such redemption, up to a maximum rate per annum of 20.0% . The Series A Preferred Units rank senior to our common units with respect to rights upon the liquidation, dissolution or winding up of the Partnership. Holders of our Series A Preferred Units have no voting rights except in limited circumstances. So long as any Series A Preferred Units remain outstanding, we will not, without the affirmative vote or consent of the holders of at least 66 2/3% of the Series A Preferred Units outstanding at the time, voting together as a single class with all series of parity securities with similar voting rights have been conferred and are exercisable, given in person or by proxy, either in writing or at a meeting: (a) authorize or create, or increase the authorized or issued amount of, any class or series of senior securities or reclassify any of our authorized equity securities into units of senior securities, or create, authorize or issue any obligation or security convertible into or evidencing the right to purchase any senior securities; (b) consummate a spin-off prior to the earlier to occur of (i) December 31, 2016 or (ii) the first day after which 2100 Energy has caused one or a series of transactions to occur whereby one or more third parties have transferred $100 million (the “Transfer Threshold”) of oil and natural gas assets to a subsidiary of us, provided that (1) any distributions or equivalents from the sale or transfer of equity in our oilfield services subsidiaries and (2) any obligations of us that have been or will be assumed by our oilfield services subsidiaries that are being spun-off, in each case without any guarantee by or recourse to us, shall, in each case, reduce the Transfer Threshold on a dollar-for-dollar basis or (c) amend, alter or repeal the provisions of our Partnership Agreement, whether by merger, consolidation or otherwise (an “Event”), so as to materially and adversely affect any right, preference, privilege or voting power of the Series A Preferred Units; provided, however, with respect to the occurrence of any Event set forth in (c) above, so long as the Series A Preferred Units remains outstanding with the terms thereof materially unchanged, the occurrence of any such Event shall not be deemed to materially and adversely affect such rights, preferences, privileges or voting power of holders of the Series A Preferred Units and, provided further, that any increase in the amount of the authorized preferred units, including the Series A Preferred Units, or the creation or issuance of any additional Series A Preferred Units or other series of preferred units, or any increase in the amount of authorized units of such series, in each case ranking on parity with or junior to the Series A Preferred Units with respect to payment of distributions, shall not be deemed to materially and adversely affect such rights, preferences, privileges or voting powers. We received net proceeds, including proceeds from the exercise of the underwriters' option, of approximately $44.4 million from this offering after deducting underwriting discounts of $2.9 million and estimated offering costs of $1.0 million . We used the net proceeds from the offering to repay a portion of the indebtedness outstanding under our credit facility. Our Series A Preferred Units are recorded as temporary equity on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015 as the units are convertible at any time at the option of the holder and become redeemable for cash on July 15, 2022. On June 18, 2015, the Partnership declared a quarterly distribution of $0.5118 , prorated for the period May 9, 2015 to July 14, 2015, per Series A Preferred Unit to holders of record on July 1, 2015. These distributions, totaling $1.0 million , were subsequently paid on July 15, 2015.

Earnings per Unit

Earnings per Unit	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Earnings per Unit	Earnings per Unit The Partnership’s net income (loss) is allocated to the common, subordinated and general partner unitholders in accordance with their respective ownership percentages. When applicable, we give effect to dividends declared and accretion related to the discount on our Series A Preferred Units as well as unvested units granted under the Partnership’s LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. We present earnings per unit regardless of whether such earnings would or could be distributed under the terms of our partnership agreement. Accordingly, the reported earnings per unit is not indicative of potential cash distributions that may be made based on historical or future earnings. Basic and diluted net income per unit is calculated by dividing net income attributable to each class of unit by the weighted average number of units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. During the three and six months ended June 30, 2015 , approximately 4,074,693 and 2,048,603 weighted average common units, respectively, issuable upon conversion of our Series A Preferred Units at the initial conversion rate and LTIP awards of 33,714 and 34,873 common units, respectively, were excluded from the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of June 30, 2014. Therefore, basic and diluted earnings per unit are the same for the three and six months ended June 30, 2014. Basic and diluted earnings per unit for the three and six months ended June 30, 2015 and 2014 were computed as follows (in thousands, except per unit amounts): Three Months Ended Six Months Ended Common Units Subordinated Units Common Units Subordinated Units General Partner (1) Net loss attributable to common, subordinated, and general partner units $ (97,513 ) $ (13,506 ) $ (147,068 ) $ (20,653 ) $ (470 ) Weighted average units outstanding 16,458 2,205 16,402 2,205 155 Basic and diluted loss per unit $ (5.92 ) $ (6.12 ) $ (8.97 ) $ (9.37 ) $ (3.03 ) __________ (1) General partner units were converted to common units effective April 27, 2015. Net loss and per unit loss reflected is the loss allocated to general partner units prior to the conversion. Three Months Ended Six Months Ended Common Units Subordinated Units General Partner Common Units Subordinated Units General Partner Net income (loss) $ 1,334 $ 235 $ 17 $ 97 $ (40 ) $ (3 ) Weighted average units outstanding 12,529 2,205 155 11,232 2,205 155 Basic and diluted income (loss) per unit $ 0.11 $ 0.11 $ 0.11 $ 0.01 $ (0.02 ) $ (0.02 )

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Ownership. At April 1, 2015, the Partnership was controlled by our general partner which was owned 69.4% by Deylau, an entity controlled by Mr. Kos, 25.0% by the David J. Chernicky Trust, and 5.6% by NSEC. Mr. Chernicky was the former Chairman of the board of directors of our general partner. Mr. Kos beneficially owns approximately 6.4% of the Partnership's outstanding common units. On April 27, 2015, the Partnership entered into a purchase agreement among the Partnership, Deylau, and 2100 Energy pursuant to which Deylau transferred an 18.4% limited liability company interest in our general partner to 2100 Energy. If 2100 Energy does not cause one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, transfer $150.0 million (or, in certain circumstances, a smaller amount) in oil and natural gas assets to a subsidiary of the Partnership by December 31, 2016, the 18.4% limited liability company interest in our general partner will revert back to Deylau. Upon completion of such transfer of assets to our subsidiary, Deylau will transfer its remaining limited liability company interest in our general partner to 2100 Energy, resulting in 2100 Energy owning a 69.4% limited liability company interest in our general partner. Consideration for the transfer of oil and natural gas assets to the Partnership will be based on fair value for the assets and approved by the board of directors of our general partner. In exchange for the transfer of Deylau's limited liability company interest in our general partner (as described above), the Partnership will also transfer all of its limited liability company interest in MCE GP, the general partner of MCLP, to an entity owned, directly or indirectly, by Deylau and Signature Investments LLC, which is wholly-owned by Mr. Tourian. Following such transactions, the Partnership will own all of the equity interests in MCLP except for the general partner interest and the Class B units. Also in April 2015, the Partnership entered into an exchange agreement with our general partner whereby our general partner eliminated the economic portion of its general partner interest in the Partnership and canceled all of its general partner units in exchange for the issuance by the Partnership of an equivalent amount of 155,102 common units. The general partner interest ceased to be an economic interest in the Partnership; however, our general partner continues to be the general partner of the Partnership. As of June 30, 2015, Mr. Chernicky beneficially owned approximately 15.1% of the Partnership's outstanding common units. Mr. Chernicky also beneficially owns 100% of the 2,205,000 subordinated units through his control of NSEC. As a result of these ownership interests in 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 wholly owned by Mr. Chernicky. Pursuant to various development agreements with the Partnership, New Dominion is currently contracted to operate the Partnership’s existing wells. In 2014, the Partnership, along with other working interest owners, reimbursed New Dominion for our proportionate share of costs incurred to construct a gas gathering system which transports production to the gas processing plant in the Greater Golden Lane field. In return, we own a portion of such gas gathering system. New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated was approximately $0.2 million as of June 30, 2015 and $0.4 million as of December 31, 2014 , all of which is classified as a long-term liability in the accompanying unaudited condensed consolidated balance sheets. Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three and six months ended June 30, 2015 and 2014 (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Producing overhead and supervision charges $ 639 $ 454 $ 1,372 $ 829 Drilling and completion supervision charges 138 39 176 48 Saltwater disposal fees 306 443 550 858 Total expenses incurred $ 1,083 $ 936 $ 2,098 $ 1,735 Receivables from New Dominion represent amounts due primarily for sale of our oil, natural gas and NGL production. Payables due to New Dominion represent amounts owed primarily for production costs associated with production of our oil, natural gas and NGL volumes. At June 30, 2015 and December 31, 2014, the Partnership had related party receivables, net from New Dominion of $5.7 million and $3.4 million , respectively. See Note 14 "Commitments and Contingencies" for discussion of litigation with our contract operator. New Source Energy GP, LLC. Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three and six months ended June 30, 2014, the amount paid to our general partner for such reimbursements was $0.3 million and $0.6 million , respectively. These expenses are included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations. Beginning in 2015, our general partner no longer billed us for these general and administrative costs as the Partnership began incurring these expenses directly. At June 30, 2015 and December 31, 2014 , $0.4 million and $2.3 million , respectively, were due to our general partner for reimbursement and included in accounts payable - related parties in the accompanying unaudited condensed consolidated balance sheets. Acquisitions. In June 2014, we exercised our option to acquire MCCS, which was owned by Mr. Kos and Mr. Tourian. See Note 2 "Acquisitions" for discussion of this acquisition. As part of the acquisition of MCCS, we assumed a payable to an entity owned by Mr. Kos and Mr. Tourian. The resulting $0.7 million related party payable was paid as of December 31, 2014. On January 9, 2015, MCES acquired two separate parcels of land, one located in Canadian County, Oklahoma and one located in Ector County, Texas, from an entity owned 50% by Mr. Kos and 50% by Mr. Tourian for approximately $0.9 million . Additionally, on February 24, 2015, MCES acquired land located in Karnes County, Texas from an entity owned 67% by Mr. Kos and 33% by Mr. Tourian for approximately $0.5 million . The purchase price for each transaction was determined based on independent third-party appraisals for each property. In each transaction, a promissory note for the entire purchase price was issued by MCES to Mr. Kos and Mr. Tourian and is payable on December 31, 2015. See Note 3 "Debt" for additional discussion on these notes payable. Since the Chairman and Chief Executive Officer of our general partner, Mr. Kos, through his control of our general partner, is deemed to control the Partnership and also controls the entities that sold MCES land, the portion of the land acquired from Mr. Kos was recorded at his carrying value, which totaled $0.6 million for the three parcels of land at the time of acquisition. The difference between Mr. Kos' carrying value and the purchase price was reflected as a reduction to equity.

Property, Plant and Equipment

Property, Plant and Equipment	6 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment Oil and Natural Gas Properties. We use the full cost method to account for our oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties, internal costs directly related to our acquisition and exploration and development activities. Under the full cost method of accounting, the net book value of oil and natural gas may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved oil and natural gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas, plus the cost of properties not subject to amortization. In calculating future net revenues, prices and costs used are based on the most recent 12-month average. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. The net book value is compared to the ceiling limitation on a quarterly and annual basis. Any excess of the net book value is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling limitation in the subsequent period. Based on the 12-month average prices of oil, natural gas and NGLs as of March, 31, 2015 and June 30, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015 and $32.9 million during the second quarter of 2015. Continued low levels or declines in oil, natural gas and NGL prices subsequent to June 30, 2015 are expected to result in additional ceiling test write downs in the third quarter of 2015 and in subsequent periods. The amount of any future impairment is difficult to predict, and will primarily depend on oil, natural gas and NGL prices during these periods. Property and Equipment, net. Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands): June 30, 2015 December 31, 2014 Vehicles and transportation equipment $ 15,970 $ 15,891 Machinery and equipment 51,680 44,441 Office furniture and equipment 2,036 1,069 Iron 13,476 12,258 Total 83,162 73,659 Less: accumulated depreciation and impairment (15,945 ) (4,773 ) 67,217 68,886 Land 1,201 — Property and equipment, net $ 68,418 $ 68,886 Due to the continued depressed commodity environment and the impact on the demand for oilfield services, the Partnership analyzed its oilfield services equipment for impairment in the second quarter of 2015. Based on current utilization rates, the decline in rental rates and consideration of sales prices for similar oilfield services equipment, the Partnership recorded an impairment on its oilfield services equipment of approximately $6.3 million for the three and six months ended June 30, 2015.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	Asset Retirement Obligations A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands): Asset retirement obligation at January 1, 2015 $ 3,681 Liability incurred upon acquiring and drilling wells — Accretion 133 Asset retirement obligation at June 30, 2015 3,814 Less current portion 117 Asset retirement obligations, net of current $ 3,697

Commitments and Contingencies

Commitments and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies Commitments The Partnership is a party to various agreements under which it has rights and obligations to participate in the acquisition and development of undeveloped properties held and to be acquired by Scintilla and New Dominion. These properties will be held by New Dominion for the benefit of the Partnership pending development of the properties. The Partnership is required by its underlying agreements with New Dominion to pay certain acreage fees to reimburse New Dominion for the cost of the acreage attributable to the Partnership’s working interest when invoiced by New Dominion. The Partnership recognizes an asset and corresponding liability as the acreage costs are incurred by New Dominion. See Note 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. New Dominion serves as the operator for all of our properties. The successful operation of our exploration and production business depends on continued utilization of New Dominion’s oil, natural gas, and NGL infrastructure and technical staff as the operator of our properties. Failure of New Dominion to perform its obligations could have a material adverse effect on our operations and our financial results. Contingent Consideration MCE. The former owners of MCE were entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE, excluding EFS, RPS and MCCS, for the trailing nine month period ended March 31, 2015, less certain adjustments. The contingent consideration was valued at $6.3 million at the acquisition date and was included in the consideration for the MCE Acquisition. Based on actual results for MCE for the nine-month period ended March 31, 2015, the MCE Contingent Consideration was deemed to have no value and no additional consideration is due. MCCS. The former owners of MCCS were entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended March 31, 2015, less certain adjustments. The contingent consideration was valued at $4.1 million at the acquisition date and was included in the consideration for the MCCS Acquisition. Based on actual results for MCCS for the nine-month period ended March 31, 2015, the MCCS Contingent Consideration was deemed to have no value and no additional consideration is due. EFS/RPS. The former owners of EFS and RPS were 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 up to 100% of the payout in common units. The EFS/RPS Contingent Consideration was valued at $22.0 million as of the acquisition date and was included in the consideration for the Services Acquisition. The fair value of the EFS/RPS Contingent Consideration was approximately $23.3 million as of December 31, 2014. In March 2015, we entered into an agreement with the former owners that allows for the payment of the cash portion of the EFS/RPS Contingent Consideration to be extended to May 2016. Beginning in June 2015, interest payments at an annual rate of 5.5% are due monthly with principal and any unpaid interest due May 1, 2016. A receivable of approximately $1.0 million due from the former owners has been offset against the contingent consideration obligation. Additionally, the contingent consideration obligation was reduced for certain costs incurred by the Partnership, as provided for in the purchase agreement. At June 30, 2015, the net contingent consideration was approximately $22.0 million . As a result of ongoing discussions with the former owners, we have not yet issued common units to satisfy the equity portion of the contingent consideration obligation. Legal Matters On January 12, 2015, David J. Chernicky, the beneficial owner of approximately 30.6% of our general partner, approximately 15.6% of our common units and all of our subordinated units, and his affiliated entities, Scintilla, LLC, New Source Energy Corporation and New Dominion (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, Mr. Kos, and former Chief Financial Officer, Richard Finley, and certain of their affiliated entities (collectively, “defendants”) in the District Court of Tulsa County, Oklahoma. The plaintiffs allege various claims against the defendants, including that plaintiffs did not receive fair value for various oil and natural gas working interests acquired from them by the Partnership. The plaintiffs also allege that the Partnership has been unjustly enriched and that the properties acquired from them by the Partnership pursuant to the transactions in question should be held in a constructive trust in favor of the plaintiffs. Additionally, the plaintiffs claim that the defendants have conspired to commit constructive fraud, breach of fiduciary duty, negligence and gross negligence against the plaintiffs. Additionally, the plaintiffs allege that the defendants have intentionally interfered with the defendants' current business arrangements with certain working interest owners in the properties the plaintiffs operate as well as future business opportunities. The plaintiffs also claim that the Partnership is wrongfully refusing to remove the restrictive legends on common units issued by the Partnership to the plaintiffs in private transactions in exchange for the oil and natural gas working interests described above. On February 23, 2015, the defendants filed several motions to dismiss the claims raised in the plaintiffs’ petition, including motions by the Partnership and our general partner that (i) the defendants' claims fail to state a claim; (ii) the defendants' claims are time barred by statues of limitations; and (iii) Tulsa County is an improper venue. A hearing on certain of the motions to dismiss was held on August 5, 2015 with another hearing scheduled for September 11, 2015. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action. In addition to the proceeding described above, on January 29, 2015, the Partnership received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by the Partnership to NSEC. The total amount of the purported claims totaled approximately $1.9 million . During 2015, New Dominion has withheld all revenue from the Partnership's sold oil and natural gas production in satisfaction of these claims and other amounts New Dominion and its affiliates claim to be owed by the Partnership. The Partnership disputes New Dominion’s claims and related withholding of revenue, and on June 4, 2015, the Partnership amended a previously filed lawsuit against New Dominion pending in the District Court of Tulsa County, Oklahoma to add certain of New Dominion’s officers as well as David Chernicky as defendants. In the lawsuit, the Partnership seeks a temporary and permanent injunction and declaratory action and asserts breach of contract, negligence, gross negligence, willful misconduct and fraud against the various defendants. No hearing date has been set in this matter. 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. Discovery is in process and scheduled to conclude in December 2015 with a class certification hearing to follow. 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	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Business Segment Information	Business Segment Information The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the production of oil and natural gas properties. Its general and administrative expenses include certain costs of our corporate administrative functions and changes in the fair value of contingent consideration obligations related to all acquisitions. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, as well as well testing and flowback services. Our oilfield services segment is the aggregation of multiple operating segments that meet the criteria for aggregation due to the economic similarities as well as the similarities in the nature of the services provided, customers served and industry regulations monitored. Management evaluates the performance of the Partnership’s business segments based on the excess of revenue over direct operating expenses or segment margin. Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands): Exploration and Production Oilfield Services Total Three Months Ended June 30, 2015 Revenues $ 5,319 $ 18,765 $ 24,084 Direct operating expenses 4,092 14,637 18,729 Segment margin 1,227 4,128 5,355 Depreciation, depletion, amortization and accretion 3,620 2,438 6,058 Impairment 32,905 66,784 99,689 General and administrative expenses 2,254 4,417 6,671 Loss from operations $ (37,552 ) $ (69,511 ) $ (107,063 ) Capital expenditures (1) $ 126 $ 14 $ 140 Three Months Ended June 30, 2014 Revenues $ 16,718 $ 10,100 $ 26,818 Direct operating expenses 5,308 5,968 11,276 Segment margin 11,410 4,132 15,542 Depreciation, depletion, amortization and accretion 6,970 3,393 10,363 General and administrative expenses 2,022 1,467 3,489 Income (loss) from operations $ 2,418 $ (728 ) $ 1,690 Capital expenditures (1) $ 7,709 $ 2,177 $ 9,886 __________ (1) On an accrual basis and exclusive of acquisitions. Exploration and Production Oilfield Services Total Six Months Ended June 30, 2015 Revenues $ 11,886 $ 50,315 $ 62,201 Direct operating expenses 8,458 37,696 46,154 Segment margin 3,428 12,619 16,047 Depreciation, depletion, amortization and accretion 8,413 10,066 18,479 Impairment 76,024 66,784 142,808 General and administrative expenses 6,823 12,082 18,905 Loss from operations $ (87,832 ) $ (76,313 ) $ (164,145 ) Capital expenditures (1) $ 1,140 $ 6,117 $ 7,257 At June 30, 2015 Total assets $ 111,793 $ 92,965 $ 204,758 Six Months Ended June 30, 2014 Revenues $ 35,569 $ 18,676 $ 54,245 Direct operating expenses 10,690 10,534 21,224 Segment margin 24,879 8,142 33,021 Depreciation, depletion, amortization and accretion 12,857 6,853 19,710 General and administrative expenses 5,866 3,184 9,050 Income (loss) from operations $ 6,156 $ (1,895 ) $ 4,261 Capital expenditures (1) $ 18,460 $ 2,991 $ 21,451 At December 31, 2014 Total assets $ 199,178 $ 176,368 $ 375,546 __________ (1) On an accrual basis and exclusive of acquisitions.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Distributions. On July 29, 2015, the Partnership suspended payment of quarterly distributions on its common units.

Basis of Presentation (Policies

Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Principles of Consolidation	Principles of Consolidation. The unaudited condensed consolidated financial statements include the accounts of the Partnership and its wholly owned and majority owned subsidiaries. Noncontrolling interest represents third-party ownership interest in a majority owned subsidiary of the Partnership and is included as a component of equity in the consolidated balance sheet and consolidated statement of unitholders' equity. All significant intercompany accounts and transactions have been eliminated in consolidation.
Interim Financial Statements	Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2014 have been derived from the audited financial statements contained in the Partnership’s 2014 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2014 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s accompanying unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2014 Form 10-K.
Reclassifications	Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Partnership's previously reported results of operations.
Use of Estimates	Use of Estimates. The preparation of the Partnership’s consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed and asset retirement obligations. Actual results could differ from those estimates.
Recently Issued Accounting Standard	Recently Issued Accounting Standards. 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 was originally effective for fiscal years beginning after December 15, 2016. In July 2015, the FASB voted to approve a one-year deferral of the effective date of ASU 2014-09. 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, if any, the guidance will have on our related disclosures. In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures. In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction from the carrying amount of the related debt. The new standard does not change the recognition and measurement of debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. Upon adoption of the guidance, assets and liabilities will decrease in the consolidated balance sheet with no impact to the consolidated statement of operations. In April 2015, the FASB issued ASU No. 2015-06, “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a consensus of the FASB Emerging Issues Task Force),” which applies to master limited partnerships that receive net assets through a dropdown transaction. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. ASU 2015-06 is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years and will be applied retrospectively. Earlier application is permitted. We are currently evaluating the effect, if any, this updated standard will have.
Oil and Natural Gas Properties	Oil and Natural Gas Properties. We use the full cost method to account for our oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties, internal costs directly related to our acquisition and exploration and development activities. Under the full cost method of accounting, the net book value of oil and natural gas may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved oil and natural gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas, plus the cost of properties not subject to amortization. In calculating future net revenues, prices and costs used are based on the most recent 12-month average. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. The net book value is compared to the ceiling limitation on a quarterly and annual basis. Any excess of the net book value is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling limitation in the subsequent period.

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2015
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands): Fair value of assets acquired and liabilities assumed: Cash $ 109 Accounts receivable 524 Inventory 2,035 Other current assets 14 Property and equipment 107 Intangible asset (1) 1,700 Goodwill (2) 3,382 Other assets 28 Total assets acquired 7,899 Accounts payable and accrued liabilities (1,431 ) Long-term debt (791 ) Total liabilities assumed (2,222 ) Net assets acquired $ 5,677 __________ (1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years . (2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS' business. Total consideration for the 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 Partnership agreed to provide additional common units in the second quarter of 2015 to the former owners of MCCS based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended 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 14 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration. (3) As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation. The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands): Fair value of assets acquired and liabilities assumed: Cash $ 1,668 Accounts receivable 22,674 Other current assets 620 Property and equipment 43,853 Intangible assets (1) 68,700 Goodwill (2) 14,224 Total assets acquired 151,739 Accounts payable and accrued liabilities (5,937 ) Factoring payable (15,840 ) Long-term debt (16,800 ) Total liabilities assumed (38,577 ) Net assets acquired $ 113,162 __________ (1) Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years . Non-compete agreements were valued based on an income approach and are amortized over the agreement period. (2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS and RPS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships. Goodwill has been allocated to the oilfield services segment. Total consideration for the Services Acquisition is as follows (in thousands): Consideration: Cash $ 57,348 Fair value of common units granted (1) 33,106 Common units granted for the benefit of EFS and RPS employees (2) 724 Contingent consideration (3) 21,984 Total fair value of consideration $ 113,162 __________ (1) The fair value of the unit consideration was based upon 1,411,777 common units valued at $23.45 per unit (closing price on the date of the acquisition). (2) The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 8 "Equity" for additional discussion of phantom units. (3) The Partnership agreed to provide additional consideration in the second quarter of 2015 to the former owners of EFS and RPS 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 at the acquisition date through the use of a probability analysis. See Note 14 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration. The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition, net of purchase price adjustments, is as follows (in thousands): Consideration: Cash $ 5,503 Fair value of common units granted (1) 11,621 Contingent consideration (2) — Total fair value of consideration $ 17,124 Fair value of assets acquired and liabilities assumed: Proved oil and natural gas properties $ 17,306 Asset retirement obligations (182 ) Total net assets $ 17,124 __________ (1) The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition). (2) The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU.
Business Acquisition, Pro Forma Information	The following unaudited pro forma combined results of operations are presented for the three and six months ended June 30, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the three and six months ended June 30, 2014 have been prepared by adjusting the historical results of the Partnership to include the historical results of the 2014 Material Acquisitions through the dates of acquisition and estimates of the effect of these transactions on the combined results. In addition, pro forma adjustments have been made assuming the units issued as consideration for these acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund the Services Acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. Three Months Ended June 30, 2014 Six Months Ended June 30, 2014 (in thousands, except per unit amounts) Revenue $ 55,881 $ 116,166 Net income attributable to New Source Energy Partners L.P. (1) $ 4,079 $ 6,186 Net income per common unit (1): Basic $ 0.24 $ 0.37 Diluted $ 0.24 $ 0.37 __________ (1) Excludes $23.9 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.
Summary of Operating Results	Three Months Ended June 30, 2014 Six Months Ended June 30, 2014 (in thousands) Revenue $ 3,054 $ 4,937 Excess of revenue over direct operating expenses $ 1,077 $ 2,196

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of Debt	The Partnership's debt consists of the following (in thousands): June 30, 2015 December 31, 2014 Credit facility $ 49,000 $ 83,000 Notes payable 17,693 20,424 Line of credit 2,367 3,619 Total debt 69,060 107,043 Less: current maturities of long-term debt 19,458 11,825 Long-term debt $ 49,602 $ 95,218

Derivative Contracts (Tables)

Derivative Contracts (Tables)	6 Months Ended
	Jun. 30, 2015
Derivative [Line Items]
Schedule of Derivative Instruments	At June 30, 2015 , the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below: Collars The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party. Collars - three way Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract. Put options The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the market price and the fixed price. Fixed price swaps The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables summarize our derivative contracts on a gross basis and the effects of netting assets and liabilities for which the right of offset exists (in thousands): June 30, 2015 Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset Net Amounts Presented Assets: Commodity derivatives - current assets $ 1,942 $ (5 ) $ 1,937 Commodity derivatives - long-term assets 3 — 3 Total $ 1,945 $ (5 ) $ 1,940 Liabilities: Commodity derivatives - current liabilities $ (5 ) $ 5 $ — Commodity derivatives - long-term liabilities (1) (56 ) — (56 ) Total $ (61 ) $ 5 $ (56 ) __________ (1) Commodity derivatives - long-term liabilities are included in other liabilities on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. December 31, 2014 Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset Net Amounts Presented Assets: Commodity derivatives - current assets $ 8,309 $ (61 ) $ 8,248 Commodity derivatives - long-term assets 1,818 — 1,818 Total $ 10,127 $ (61 ) $ 10,066 Liabilities: Commodity derivatives - current liabilities $ 61 $ (61 ) $ — Commodity derivatives - long-term liabilities — — — Total $ 61 $ (61 ) $ — The following tables set 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): June 30, 2015 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 $ — $ 667 $ — $ 667 Natural gas put options — 140 — 140 Oil, natural gas and NGL fixed price swaps — 1,077 — 1,077 Total $ — $ 1,884 $ — $ 1,884 December 31, 2014 Fair Value Measurements Description Active Markets for Identical Assets (Level 1) Observable Inputs (Level 2) Unobservable Inputs (Level 3) Total Carrying Value Oil and natural gas collars $ — $ 2,411 $ — $ 2,411 Oil, natural gas and NGL put options — 1,405 — 1,405 Oil, natural gas and NGL fixed price swaps — 6,250 — 6,250 Contingent consideration — — (23,330 ) (23,330 ) Total $ — $ 10,066 $ (23,330 ) $ (13,264 ) The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six months ended June 30, 2014 (in thousands): Three Months Ended Six Months Ended Beginning balance $ (2,843 ) $ (2,517 ) Loss on derivative contracts — (2,432 ) Transfers out (1) 2,843 2,843 Cash received upon settlement — 2,106 Ending balance (1) $ — $ — Unrealized losses included in earnings relating to derivatives held at period end $ — $ — __________ (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.
Derivative Instruments, Gain (Loss)	The following table presents cash settlements on our derivative contracts as included in (loss) gain on derivative contracts, net in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Cash receipts (payments) upon settlement (1) $ 6,000 $ (983 ) $ 8,339 $ (3,412 ) __________ (1) Cash receipts upon settlement of derivative contracts for the three and six months ended June 30, 2015 includes $3.9 million related to the settlement of certain derivative contracts with contract maturities subsequent to the period in which they were settled ("early settlements"). In the second quarter of 2015, we monetized certain of our derivative contracts for the periods October 2015 through December 2015 and calendar year 2016.
Oil Collar [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	The following tables present our derivative instruments outstanding as of June 30, 2015 : Oil collars Volumes Floor Price Ceiling Price July 2015 - September 2015 9,317 $ 80.00 $ 93.25 October 2015 - December 2015 26,220 $ 55.00 $ 67.00 January 2016 - March 2016 25,935 $ 55.00 $ 67.00 April 2016 - December 2016 45,375 $ 55.00 $ 69.20
Oil Collars - Three Way [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	Oil collars - three way Volumes Sold Put Purchased Put Ceiling Price July 2015 - December 2015 9,200 $ 77.50 $ 92.50 $ 102.60
Oil Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	Oil fixed price swaps Volumes (Bbls) Weighted Average Fixed Price July 2015 - September 2015 10,777 $ 88.90
Natural Gas Collars [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	Natural gas collars Volumes Floor Price Ceiling Price July 2015 - September 2015 325,114 $ 4.00 $ 4.32 October 2015 - December 2015 340,400 $ 2.85 $ 3.46 January 2016 - March 2016 336,700 $ 2.85 $ 3.46 April 2016 - December 2016 1,017,500 $ 2.85 $ 3.40
Natural Gas Options [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	Natural gas put options Volumes (MMBtu) Floor Price July 2015 - December 2015 210,876 $ 3.50
Natural Gas Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	Natural gas fixed price swaps Volumes (MMBtu) Weighted Average Fixed Price July 2015 - September 2015 194,461 $ 4.25
Natural Gas Liquid Swaps [Member]
Derivative [Line Items]
Schedule of Derivative Instruments	NGL fixed price swaps Volumes Weighted Average Fixed Price July 2015 - September 2015 20,782 $ 75.18

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables summarize our derivative contracts on a gross basis and the effects of netting assets and liabilities for which the right of offset exists (in thousands): June 30, 2015 Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset Net Amounts Presented Assets: Commodity derivatives - current assets $ 1,942 $ (5 ) $ 1,937 Commodity derivatives - long-term assets 3 — 3 Total $ 1,945 $ (5 ) $ 1,940 Liabilities: Commodity derivatives - current liabilities $ (5 ) $ 5 $ — Commodity derivatives - long-term liabilities (1) (56 ) — (56 ) Total $ (61 ) $ 5 $ (56 ) __________ (1) Commodity derivatives - long-term liabilities are included in other liabilities on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. December 31, 2014 Gross Amounts of Recognized Assets and Liabilities Gross Amounts Offset Net Amounts Presented Assets: Commodity derivatives - current assets $ 8,309 $ (61 ) $ 8,248 Commodity derivatives - long-term assets 1,818 — 1,818 Total $ 10,127 $ (61 ) $ 10,066 Liabilities: Commodity derivatives - current liabilities $ 61 $ (61 ) $ — Commodity derivatives - long-term liabilities — — — Total $ 61 $ (61 ) $ — The following tables set 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): June 30, 2015 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 $ — $ 667 $ — $ 667 Natural gas put options — 140 — 140 Oil, natural gas and NGL fixed price swaps — 1,077 — 1,077 Total $ — $ 1,884 $ — $ 1,884 December 31, 2014 Fair Value Measurements Description Active Markets for Identical Assets (Level 1) Observable Inputs (Level 2) Unobservable Inputs (Level 3) Total Carrying Value Oil and natural gas collars $ — $ 2,411 $ — $ 2,411 Oil, natural gas and NGL put options — 1,405 — 1,405 Oil, natural gas and NGL fixed price swaps — 6,250 — 6,250 Contingent consideration — — (23,330 ) (23,330 ) Total $ — $ 10,066 $ (23,330 ) $ (13,264 ) The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three and six months ended June 30, 2014 (in thousands): Three Months Ended Six Months Ended Beginning balance $ (2,843 ) $ (2,517 ) Loss on derivative contracts — (2,432 ) Transfers out (1) 2,843 2,843 Cash received upon settlement — 2,106 Ending balance (1) $ — $ — Unrealized losses included in earnings relating to derivatives held at period end $ — $ — __________ (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.

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands): Goodwill at December 31, 2014 $ 9,315 Impairment (9,315 ) Goodwill at June 30, 2015 $ —
Schedule of Finite-Lived Intangible Assets	A reconciliation of the Partnership's intangible assets for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands): Intangible assets, net, at December 31, 2014 $ 56,377 Amortization expense (5,166 ) Impairment (51,211 ) Intangible assets, net, at June 30, 2015 $ —

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2015
Equity [Abstract]
Schedule of Distributions Made to Units	Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the six months ended June 30, 2015 and 2014 , are shown in the following table (in thousands, except per unit amounts): Distributions Declaration Date Payable Date Distribution per Unit Common Units Subordinated Units General Partner Units Total 2015 First Quarter May 8, 2015 May 15, 2015 $ 0.20 $ 3,312 $ — $ — $ 3,312 Second Quarter N/A N/A $ — $ — $ — $ — $ — 2014 First Quarter April 21, 2014 May 15, 2014 $ 0.580 $ 7,852 $ 1,279 $ 90 $ 9,221 Second Quarter July 21, 2014 August 15, 2014 $ 0.585 $ 9,025 $ 1,290 $ 91 $ 10,406
Schedule of Target Distributions to Unitholders	The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels, as adjusted based on the MCCS Acquisition. Marginal Percentage Interest in Total Quarterly Distributions per MCE Unit MCE Class A Unitholders (the Partnership) MCE Class B Unitholders Minimum Quarterly Distribution $16,116 100% —% First Target Distribution $18,533 to $20,144 85% 15% Second Target Distribution $20,145 to $24,173 75% 25% Third Target Distribution and Thereafter $24,174 and above 50% 50%

Earnings per Unit (Tables)

Earnings per Unit (Tables)	6 Months Ended
	Jun. 30, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	Basic and diluted earnings per unit for the three and six months ended June 30, 2015 and 2014 were computed as follows (in thousands, except per unit amounts): Three Months Ended Six Months Ended Common Units Subordinated Units Common Units Subordinated Units General Partner (1) Net loss attributable to common, subordinated, and general partner units $ (97,513 ) $ (13,506 ) $ (147,068 ) $ (20,653 ) $ (470 ) Weighted average units outstanding 16,458 2,205 16,402 2,205 155 Basic and diluted loss per unit $ (5.92 ) $ (6.12 ) $ (8.97 ) $ (9.37 ) $ (3.03 ) __________ (1) General partner units were converted to common units effective April 27, 2015. Net loss and per unit loss reflected is the loss allocated to general partner units prior to the conversion. Three Months Ended Six Months Ended Common Units Subordinated Units General Partner Common Units Subordinated Units General Partner Net income (loss) $ 1,334 $ 235 $ 17 $ 97 $ (40 ) $ (3 ) Weighted average units outstanding 12,529 2,205 155 11,232 2,205 155 Basic and diluted income (loss) per unit $ 0.11 $ 0.11 $ 0.11 $ 0.01 $ (0.02 ) $ (0.02 )

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three and six months ended June 30, 2015 and 2014 (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Producing overhead and supervision charges $ 639 $ 454 $ 1,372 $ 829 Drilling and completion supervision charges 138 39 176 48 Saltwater disposal fees 306 443 550 858 Total expenses incurred $ 1,083 $ 936 $ 2,098 $ 1,735

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	6 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands): June 30, 2015 December 31, 2014 Vehicles and transportation equipment $ 15,970 $ 15,891 Machinery and equipment 51,680 44,441 Office furniture and equipment 2,036 1,069 Iron 13,476 12,258 Total 83,162 73,659 Less: accumulated depreciation and impairment (15,945 ) (4,773 ) 67,217 68,886 Land 1,201 — Property and equipment, net $ 68,418 $ 68,886

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands): Asset retirement obligation at January 1, 2015 $ 3,681 Liability incurred upon acquiring and drilling wells — Accretion 133 Asset retirement obligation at June 30, 2015 3,814 Less current portion 117 Asset retirement obligations, net of current $ 3,697

Business Segment Information (T

Business Segment Information (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands): Exploration and Production Oilfield Services Total Three Months Ended June 30, 2015 Revenues $ 5,319 $ 18,765 $ 24,084 Direct operating expenses 4,092 14,637 18,729 Segment margin 1,227 4,128 5,355 Depreciation, depletion, amortization and accretion 3,620 2,438 6,058 Impairment 32,905 66,784 99,689 General and administrative expenses 2,254 4,417 6,671 Loss from operations $ (37,552 ) $ (69,511 ) $ (107,063 ) Capital expenditures (1) $ 126 $ 14 $ 140 Three Months Ended June 30, 2014 Revenues $ 16,718 $ 10,100 $ 26,818 Direct operating expenses 5,308 5,968 11,276 Segment margin 11,410 4,132 15,542 Depreciation, depletion, amortization and accretion 6,970 3,393 10,363 General and administrative expenses 2,022 1,467 3,489 Income (loss) from operations $ 2,418 $ (728 ) $ 1,690 Capital expenditures (1) $ 7,709 $ 2,177 $ 9,886 __________ (1) On an accrual basis and exclusive of acquisitions. Exploration and Production Oilfield Services Total Six Months Ended June 30, 2015 Revenues $ 11,886 $ 50,315 $ 62,201 Direct operating expenses 8,458 37,696 46,154 Segment margin 3,428 12,619 16,047 Depreciation, depletion, amortization and accretion 8,413 10,066 18,479 Impairment 76,024 66,784 142,808 General and administrative expenses 6,823 12,082 18,905 Loss from operations $ (87,832 ) $ (76,313 ) $ (164,145 ) Capital expenditures (1) $ 1,140 $ 6,117 $ 7,257 At June 30, 2015 Total assets $ 111,793 $ 92,965 $ 204,758 Six Months Ended June 30, 2014 Revenues $ 35,569 $ 18,676 $ 54,245 Direct operating expenses 10,690 10,534 21,224 Segment margin 24,879 8,142 33,021 Depreciation, depletion, amortization and accretion 12,857 6,853 19,710 General and administrative expenses 5,866 3,184 9,050 Income (loss) from operations $ 6,156 $ (1,895 ) $ 4,261 Capital expenditures (1) $ 18,460 $ 2,991 $ 21,451 At December 31, 2014 Total assets $ 199,178 $ 176,368 $ 375,546 __________ (1) On an accrual basis and exclusive of acquisitions.

Acquisitions (Details)

Acquisitions (Details)		Jun. 26, 2014USD ($)$ / sharesshares		Jan. 31, 2014USD ($)producing_well$ / sharesshares	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)producing_wellshares
Business Acquisition [Line Items]
Gain on acquisition of business					$ 0	$ 2,298,000	$ 0	$ 2,298,000
Common Units [Member]
Business Acquisition [Line Items]
Issuance of common units in acquisitions (in units) | shares									1,964,957
Southern Dome [Member]
Business Acquisition [Line Items]
Number of wells in which Company has acquired working interests | producing_well									23
CEU Paradigm [Member]
Business Acquisition [Line Items]
Number of wells in which Company has acquired working interests | producing_well				23
Total fair value of consideration				$ 17,124,000
Issuance of common units in acquisitions (in units) | shares				488,667
Value of units issued in acquisition (in usd per unit) | $ / shares				$ 23.78
Contingent consideration	[1]			$ 0
MCCS [Member]
Business Acquisition [Line Items]
Total fair value of consideration		$ 5,677,000
Issuance of common units in acquisitions (in units) | shares		33,646
Value of units issued in acquisition (in usd per unit) | $ / shares		$ 23.45
Equity interest percentage acquired in acquisition		100.00%
Contingent consideration		$ 4,057,000	[2]		6,300,000		$ 6,300,000
Gain on acquisition of business		2,300,000
Intangible asset	[3]	$ 1,700,000
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
EFS [Member]
Business Acquisition [Line Items]
Equity interest percentage acquired in acquisition		100.00%
EFS [Member] | EFS Employees [Member]
Business Acquisition [Line Items]
Issuance of common units in acquisitions (in units) | shares		30,867
Value of units issued in acquisition (in usd per unit) | $ / shares		$ 23.45
RPS [Member]
Business Acquisition [Line Items]
Equity interest percentage acquired in acquisition		100.00%
EFS and RPS [Member]
Business Acquisition [Line Items]
Total fair value of consideration		$ 113,162,000
Issuance of common units in acquisitions (in units) | shares		1,411,777
Value of units issued in acquisition (in usd per unit) | $ / shares		$ 23.45
Contingent consideration		$ 21,984,000	[4]		$ 22,000,000		$ 22,000,000		$ 23,300,000
Intangible asset	[5]	$ 68,700,000
EFS and RPS [Member] | Common Units [Member] | Phantom Units [Member]
Business Acquisition [Line Items]
Phantom units granted (in units) | shares		432,038
EFS and RPS [Member] | Service Requirement Units [Member] | Common Units [Member] | Phantom Units [Member]
Business Acquisition [Line Items]
Phantom units granted (in units) | shares		401,171
EFS and RPS [Member] | Customer Relationships [Member]
Business Acquisition [Line Items]
Useful life of finite-lived intangible asset							7 years
Intangible asset		$ 64,200,000
EFS and RPS [Member] | Noncompete Agreements [Member]
Business Acquisition [Line Items]
Intangible asset		$ 4,500,000
2014 Material Acquisitions [Member] | General and Administrative Expense [Member]
Business Acquisition [Line Items]
Acquisition cost and transaction bonuses								1,300,000
2014 Material Acquisitions [Member] | EFS and RPS Employees [Member]
Business Acquisition [Line Items]
Acquisition cost and transaction bonuses								$ 23,900,000
[1]	The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU.
[2]	The Partnership agreed to provide additional common units in the second quarter of 2015 to the former owners of MCCS based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended 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 14 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
[3]	Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years
[4]	The Partnership agreed to provide additional consideration in the second quarter of 2015 to the former owners of EFS and RPS 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 at the acquisition date through the use of a probability analysis. See Note 14 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.
[5]	Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years. Non-compete agreements were valued based on an income approach and are amortized over the agreement period.

Acquisitions (Purchase Price Al

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

Acquisitions (Purchase Price 37

Acquisitions (Purchase Price Allocation for MCCS Acquisition) (Details) - USD ($) $ in Thousands		Jun. 26, 2014		Jun. 30, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Noncontrolling interest				$ 17,420	$ 17,420
MCCS [Member]
Business Acquisition [Line Items]
Fair value of common units granted	[1]	$ 789
Contingent consideration		4,057	[2]	$ 6,300
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 Partnership agreed to provide additional common units in the second quarter of 2015 to the former owners of MCCS based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended 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 14 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
[3]	As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.

Acquisitions (Summary of Assets

Acquisitions (Summary of Assets Acquired and Liabilities Assumed in MCCS Acquisition) (Details) - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014	Jun. 26, 2014
Business Acquisition [Line Items]
Goodwill		$ 0	$ 9,315
MCCS [Member]
Business Acquisition [Line Items]
Cash				$ 109
Accounts receivable				524
Inventory				2,035
Other current assets				14
Property and equipment				107
Intangible asset	[1]			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)
Total net assets				$ 5,677
[1]	Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years
[2]	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS' business.

Acquisitions (Purchase Price 39

Acquisitions (Purchase Price Allocation of EFS and RPS Acquisition) (Details) - EFS and RPS [Member] - USD ($) $ in Thousands		Jun. 26, 2014		Jun. 30, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Cash		$ 57,348
Fair value of common units granted	[1]	33,106
Contingent consideration		21,984	[2]	$ 22,000	$ 23,300
Total fair value of consideration		113,162
EFS and RPS Employees [Member]
Business Acquisition [Line Items]
Common units granted for the benefit of EFS and RPS employees	[3]	$ 724
[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 Partnership agreed to provide additional consideration in the second quarter of 2015 to the former owners of EFS and RPS 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 at the acquisition date through the use of a probability analysis. See Note 14 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.
[3]	The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 8 "Equity" for additional discussion of phantom units.

Acquisitions (Summary of Asse40

Acquisitions (Summary of Assets Acquired and Liabilities Assumed in EFS and RPS Acquisition) (Details) - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014	Jun. 26, 2014
Business Acquisition [Line Items]
Goodwill		$ 0	$ 9,315
EFS and RPS [Member]
Business Acquisition [Line Items]
Cash				$ 1,668
Accounts receivable				22,674
Other current assets				620
Property and equipment				43,853
Intangible asset	[1]			68,700
Goodwill	[2]			14,224
Total assets acquired				151,739
Accounts payable and accrued liabilities				(5,937)
Factoring payable				(15,840)
Long-term debt				(16,800)
Total liabilities assumed				(38,577)
Total net assets				$ 113,162
[1]	Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years. Non-compete agreements were valued based on an income approach and are amortized over the agreement period.
[2]	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS and RPS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships. Goodwill has been allocated to the oilfield services segment.

Acquisitions (Pro Forma Results

Acquisitions (Pro Forma Results of Operations) (Details) - Jun. 30, 2014 - 2014 Material Acquisitions [Member] - USD ($) $ / shares in Units, $ in Thousands		Total	Total
Business Acquisition [Line Items]
Revenue		$ 55,881	$ 116,166
Net income attributable to New Source Energy Partners L.P.	[1]	$ 4,079	$ 6,186
Net income per common unit (1):
Basic (in usd per unit)	[1]	$ 0.24	$ 0.37
Diluted (in usd per unit)		$ 0.24	$ 0.37
[1]	Excludes $23.9 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.

Acquisitions (Amounts of Revenu

Acquisitions (Amounts of Revenues and Revenues in Excess of Direct Operating Expenses Included in Statement of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Business Acquisition [Line Items]
Revenue	$ 24,084	$ 26,818	$ 62,201	$ 54,245
Excess of revenue over direct operating expenses	$ (107,063)	1,690	$ (164,145)	4,261
2014 Material Acquisitions [Member]
Business Acquisition [Line Items]
Revenue		3,054		4,937
Excess of revenue over direct operating expenses		$ 1,077		$ 2,196

Debt (Schedule of Debt) (Detail

Debt (Schedule of Debt) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Outstanding Credit	$ 49,000	$ 83,000
Notes payable	17,693	20,424
Total debt	69,060	107,043
Less: current maturities of long-term debt	19,458	11,825
Long-term debt	49,602	95,218
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Outstanding Credit	$ 2,367	$ 3,619

Debt (Senior Secured Revolving

Debt (Senior Secured Revolving Credit Facility - Narrative) (Details) - USD ($)	6 Months Ended
	Jun. 30, 2015	Jun. 29, 2015	May. 29, 2015	Dec. 31, 2014
Line of Credit Facility [Line Items]
Outstanding balance of line of credit	$ 49,000,000			$ 83,000,000
Available borrowing capacity	$ 8,000,000
Commitment fee percentage	0.50%
Interest rates on debt instruments	3.19%			3.44%
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit current borrowing capacity	$ 60,000,000	$ 90,000,000	$ 57,000,000
Outstanding balance of line of credit	$ 2,367,000			$ 3,619,000
Minimum [Member]
Line of Credit Facility [Line Items]
Required ratio of EBITDA to interest expense	2.5
Required current ratio	1
Maximum [Member]
Line of Credit Facility [Line Items]
Required ratio of total debt to EBITDA	3.5
Federal Funds Rate [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	0.50%
London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	1.00%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	3.25%
Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	1.50%
Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Basis spread on debt instruments	2.25%
Eighth Amendment [Member]
Line of Credit Facility [Line Items]
Cap on yearly cash distributions	$ 6,000,000
Maximum borrowing base utilization permitted under credit facility	90.00%

Debt (Notes Payable - Narrative

Debt (Notes Payable - Narrative) (Details)	Feb. 24, 2015USD ($)	Jun. 30, 2015USD ($)	Oct. 01, 2015USD ($)	Dec. 31, 2014USD ($)
Debt Instrument [Line Items]
Current portion of long-term debt		$ 19,458,000		$ 11,825,000
Interest rates on debt instruments		3.19%		3.44%
MidCentral Energy Partners LP [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Short-term debt	$ 1,400,000
Chief Executive Officer [Member] | MidCentral Energy Partners LP [Member]
Debt Instrument [Line Items]
Ownership percentage	50.00%
President [Member] | MidCentral Energy Partners LP [Member]
Debt Instrument [Line Items]
Ownership percentage	50.00%
Prime Rate [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments	1.00%
Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Long-term debt		$ 5,500,000
Current portion of long-term debt		$ 4,900,000
Required fixed-charge ratio		1.25
Loans Payable [Member]
Debt Instrument [Line Items]
Term loans balance		$ 10,800,000
Initial deposit required for loans		$ 500,000
Loans Payable [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments		(2.30%)
Interest rates on debt instruments		5.50%
Minimum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments		1.50%
Minimum [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Durations of debt instruments		12 months
Stated rates on debt instruments		5.50%
Minimum [Member] | Loans Payable [Member]
Debt Instrument [Line Items]
Minimum balance required to be maintained on reserve bank account		$ 300,000
Minimum [Member] | Loans Payable [Member] | EFS and RPS [Member]
Debt Instrument [Line Items]
Required fixed-charge ratio		1.25
Required working capital and cash balance		$ 1,000,000
Minimum [Member] | Loans Payable [Member] | EFS and RPS [Member] | Scenario, Forecast [Member]
Debt Instrument [Line Items]
Required working capital and cash balance			$ 3,500,000
Minimum [Member] | Loans Payable [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Stated rates on debt instruments		5.50%
Maximum [Member] | Base Rate [Member]
Debt Instrument [Line Items]
Basis spread on debt instruments		2.25%
Maximum [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Durations of debt instruments		60 months
Stated rates on debt instruments		10.51%
Maximum [Member] | Loans Payable [Member] | EFS and RPS [Member]
Debt Instrument [Line Items]
Required leverage ratio		1.5

Debt (Line of Credit - Narrativ

Debt (Line of Credit - Narrative) (Details)	6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 29, 2015USD ($)	May. 29, 2015USD ($)	Dec. 31, 2014USD ($)	Feb. 28, 2014USD ($)
Line of Credit Facility [Line Items]
Interest rates on debt instruments	3.19%			3.44%
Outstanding balance of line of credit	$ 49,000,000			$ 83,000,000
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit current borrowing capacity	60,000,000	$ 90,000,000	$ 57,000,000
Outstanding balance of line of credit	2,367,000			$ 3,619,000
Revolving Credit Facility [Member] | MidCentral Energy Services [Member]
Line of Credit Facility [Line Items]
Line of credit maximum borrowing capacity	3,000,000				$ 4,000,000
Line of credit current borrowing capacity					$ 4,000,000
Outstanding balance of line of credit	$ 2,400,000
Required debt service coverage ratio	1.25
Revolving Credit Facility [Member] | Bank of Oklahoma Corporation National Prime Rate [Member]
Line of Credit Facility [Line Items]
Interest rates on debt instruments	4.00%

Factoring Payable (Details)

Factoring Payable (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Factoring Payable [Line Items]
Percentage of funding from factoring payable received upfront	90.00%
Percentage of balance of payables factored that is reserved	10.00%
Days till outstanding factored payable are repurchased	90 days
Factoring payable	$ 5,098	$ 13,152
London Interbank Offered Rate (LIBOR) [Member]
Factoring Payable [Line Items]
Interest margin on factoring payables	3.00%

Derivative Contracts (Commodity

Derivative Contracts (Commodity Derivative Positions Oil Collars) (Details) - Jun. 30, 2015 - Not Designated as Hedging Instrument [Member]	$ / bblbbl
Oil Collars July 2015 - September 2015 [Member]
Derivative [Line Items]
Volumes (Bbls) | bbl	9,317
Floor Price (in usd per Bbl)	80
Ceiling Price (in usd per Bbl)	93.25
Oil Collars October 2015 - December 2015 [Member]
Derivative [Line Items]
Volumes (Bbls) | bbl	26,220
Floor Price (in usd per Bbl)	55
Ceiling Price (in usd per Bbl)	67
Oil Collars January 2016 - March 2016 [Member]
Derivative [Line Items]
Volumes (Bbls) | bbl	25,935
Floor Price (in usd per Bbl)	55
Ceiling Price (in usd per Bbl)	67
Oil Collars April 2016 - December 2016 [Member]
Derivative [Line Items]
Volumes (Bbls) | bbl	45,375
Floor Price (in usd per Bbl)	55
Ceiling Price (in usd per Bbl)	69.2

Derivative Contracts (Commodi49

Derivative Contracts (Commodity Derivative Positions of Oil Collars - Three Way) (Details) - Jun. 30, 2015 - Oil Collars - Three Way July 2015 - December 2015 [Member] - Not Designated as Hedging Instrument [Member]	$ / bblbbl
Derivative [Line Items]
Volumes (Bbls) | bbl	9,200
Sold Put (in usd per Bbl)	77.50
Purchased Put (in usd per Bbl)	92.50
Ceiling Price (in usd per Bbl)	102.60

Derivative Contracts (Commodi50

Derivative Contracts (Commodity Derivative Positions Oil Fixed Price Swaps) (Details) - Jun. 30, 2015 - Not Designated as Hedging Instrument [Member] - Oil Fixed Price Swaps July 2015 - September 2015 [Member]	$ / bblbbl
Derivative [Line Items]
Volumes (Bbls) | bbl	10,777
Weighted Average Fixed Price (in usd per Bbl)	88.90

Derivative Contracts (Commodi51

Derivative Contracts (Commodity Derivative Positions Natural Gas Collars) (Details) - Jun. 30, 2015 - Not Designated as Hedging Instrument [Member]	MMBTU$ / MMBTU
Natural Gas Collars July 2015 - September 2015 [Member]
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	325,114
Floor Price (in usd per MMBtu)	4
Ceiling Price (in usd per MMBtu)	4.32
Natural Gas Collars October 2015 - December 2015 [Member]
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	340,400
Floor Price (in usd per MMBtu)	2.85
Ceiling Price (in usd per MMBtu)	3.46
Natural Gas Collars January 2016 - March 2016 [Member]
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	336,700
Floor Price (in usd per MMBtu)	2.85
Ceiling Price (in usd per MMBtu)	3.46
Natural Gas Collars April 2016 - December 2016 [Member]
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	1,017,500
Floor Price (in usd per MMBtu)	2.85
Ceiling Price (in usd per MMBtu)	3.40

Derivative Contracts (Commodi52

Derivative Contracts (Commodity Derivative Positions Natural Gas Options) (Details) - Jun. 30, 2015 - Natural Gas Put Options July 2015 - December 2015 [Member] - Not Designated as Hedging Instrument [Member]	MMBTU$ / MMBTU
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	210,876
Floor Price (in usd per MMBtu)	3.5

Derivative Contracts (Commodi53

Derivative Contracts (Commodity Derivative Positions Natural Gas Swaps) (Details) - Jun. 30, 2015 - Not Designated as Hedging Instrument [Member] - Natural Gas Fixed Price Swaps July 2015 - September 2015 [Member]	MMBTU$ / MMBTU
Derivative [Line Items]
Volumes (MMBtu) | MMBTU	194,461
Weighted Average Fixed Price (in usd per MMBtu)	4.25

Derivative Contracts (Commodi54

Derivative Contracts (Commodity Derivative Positions Liquid Swaps) (Details) - Jun. 30, 2015 - NGL Fixed Price Swap July 2015 - September 2015 [Member] - Not Designated as Hedging Instrument [Member]	$ / bblbbl
Derivative [Line Items]
Volumes (Bbls) | bbl	20,782
Weighted Average Fixed Price (in usd per Bbl)	75.18

Derivative Contracts (Offsettin

Derivative Contracts (Offsetting Commodity Derivative Assets and Liabilities) (Details) - Commodity [Member] - USD ($) $ in Thousands	Jun. 30, 2015		Dec. 31, 2014
Derivative [Line Items]
Gross Amounts of Recognized Assets	$ 1,945		$ 10,127
Gross Amounts Offset	(5)		(61)
Net Amounts Presented	1,940		10,066
Gross Amounts of Recognized Liabilities	(61)		61
Gross Amounts Offset	5		(61)
Net Amounts Presented	(56)		0
Current Assets [Member]
Derivative [Line Items]
Gross Amounts of Recognized Assets	1,942		8,309
Gross Amounts Offset	(5)		(61)
Net Amounts Presented	1,937		8,248
Long-term Assets [Member]
Derivative [Line Items]
Gross Amounts of Recognized Assets	3		1,818
Gross Amounts Offset	0		0
Net Amounts Presented	3		1,818
Current Liabilities [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities	(5)		61
Gross Amounts Offset	5		(61)
Net Amounts Presented	0		0
Long-term Liabilities [Member]
Derivative [Line Items]
Gross Amounts of Recognized Liabilities	(56)	[1]	0
Gross Amounts Offset	0	[1]	0
Net Amounts Presented	$ (56)	[1]	$ 0
[1]	Commodity derivatives - long-term liabilities are included in other liabilities on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015.

Derivative Contracts (Gains (Lo

Derivative Contracts (Gains (Losses) on Derivative Contracts) (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash receipts (payments) upon settlement	[1]	$ 6,000	$ (983)	$ 8,339	$ (3,412)
Net cash receipts related to settlement of certain derivative contracts		$ 3,500		$ 3,900
[1]	Cash receipts upon settlement of derivative contracts for the three and six months ended June 30, 2015 includes $3.9 million related to the settlement of certain derivative contracts with contract maturities subsequent to the period in which they were settled ("early settlements"). In the second quarter of 2015, we monetized certain of our derivative contracts for the periods October 2015 through December 2015 and calendar year 2016.

Fair Value Measurements (Deriva

Fair Value Measurements (Derivative Assets and Contingent Consideration Measured at Fair Value) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	[1]	Mar. 31, 2014	Dec. 31, 2013
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		$ (2,843)	$ (2,517)
Fair Value, Measurements, Recurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	$ 1,884
Contingent consideration		$ (23,330)
Total		(13,264)
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	0
Contingent consideration		0
Total		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	1,884
Contingent consideration		0
Total		10,066
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	0
Contingent consideration		(23,330)
Total		(23,330)
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	667
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	667
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	140
Fair Value, Measurements, Recurring [Member] | Natural Gas and NGL Puts [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	0
Fair Value, Measurements, Recurring [Member] | Natural Gas and NGL Puts [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	140
Fair Value, Measurements, Recurring [Member] | Natural Gas and NGL Puts [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	0
Fair Value, Measurements, Recurring [Member] | Oil, Natural Gas and NGL Swaps [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	1,077
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	1,077
Fair Value, Measurements, Recurring [Member] | Oil, Natural Gas and NGL Swaps [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative	$ 0
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		2,411
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		0
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		2,411
Fair Value, Measurements, Recurring [Member] | Oil Collar [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		0
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		1,405
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		0
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		1,405
Fair Value, Measurements, Recurring [Member] | Natural Gas Collars [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		0
Fair Value, Measurements, Recurring [Member] | Oil Put Options [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		6,250
Fair Value, Measurements, Recurring [Member] | Oil Put Options [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		0
Fair Value, Measurements, Recurring [Member] | Oil Put Options [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative		6,250
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
[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.

Goodwill and Intangible Asset58

Goodwill and Intangible Assets (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Impairment		$ 9,315
Amortization expense	$ 3,100	5,166	$ 6,200
Impairment of Intangible Assets, Finite-lived		$ 51,211

Fair Value Measurements (Fair V

Fair Value Measurements (Fair Value of Allocated Derivative Assets and Liabilities) (Details) - Jun. 30, 2014 - Fair Value, Inputs, Level 3 [Member] - USD ($) $ in Thousands		Total	Total
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Beginning balance		$ (2,843)	$ (2,517)
Loss on derivative contracts		0	(2,432)
Transfers out	[1]	2,843	2,843
Cash received upon settlement		0	2,106
Ending balance	[1]	0	0
Unrealized losses included in earnings relating to derivatives held at period end		$ 0	$ 0
[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.

Goodwill and Intangible Asset60

Goodwill and Intangible Assets (Schedule of Goodwill) (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2015USD ($)
Goodwill [Roll Forward]
Goodwill at December 31, 2014	$ 9,315
Impairment	(9,315)
Goodwill at June 30, 2015	$ 0

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Outstanding balance of line of credit	$ 49,000	$ 83,000
Notes payable	$ 17,693	$ 20,424

Goodwill and Intangible Asset62

Goodwill and Intangible Assets (Schedule of Finite-Lived Intangible Assets) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Finite-lived Intangible Assets [Roll Forward]
Intangible assets at December 31, 2014		$ 56,377
Amortization expense	$ (3,100)	(5,166)	$ (6,200)
Impairment		(51,211)
Intangible assets at June 30, 2015		$ 0

Equity (Equity Offerings - Narr

Equity (Equity Offerings - Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Jun. 02, 2015	May. 08, 2015	Apr. 30, 2014	Dec. 31, 2014
Class of Stock [Line Items]
Net proceeds from offering used to repay credit facility			$ 5
Common Units [Member]
Class of Stock [Line Items]
Issuance of common units in acquisitions (in units)				1,964,957
Common partnership units sold in public offering			3,450,000
Unit price of units sold in public offering (in usd per unit)			$ 23.25
Proceeds from public offering of common partnership units			$ 76.2
Underwriter's fees associated with public sale of common units			3.6
Offering costs associated with public sale of common units			$ 0.3
Series A Cumulative Convertible Preferred Units [Member]
Class of Stock [Line Items]
Public offering of units		$ 44
Unit price (in usd per unit)		$ 25
Additional units available to underwrites (in shares)	264,000
Option period for underwriters to purchase additional units		30 days
Additional units issued (in units)	170,000
Proceeds from issuance of Series A preferred units	$ 4

Equity (Schedule of Distributio

Equity (Schedule of Distributions) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Mar. 31, 2014
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions paid (in usd per unit)	$ 0	$ 0.2	$ 0.585	$ 0.580
Distributions	$ 0	$ 3,312	$ 10,406	$ 9,221
Common Units [Member]
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	0	3,312	9,025	7,852
Subordinated Units [Member]
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	0	0	1,290	1,279
General Partnership Units [Member]
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	$ 0	$ 0	$ 91	$ 90

Equity (Distribution - Narrativ

Equity (Distribution - Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended
	Mar. 31, 2015	Jun. 30, 2015
Distribution Made to Limited Partner [Line Items]
Days after quarter end in which distributions are declared and distributed		45 days
Distributions declared (in usd per unit)	$ 0.20
Class B Units [Member]
Distribution Made to Limited Partner [Line Items]
Distributions		$ 14

Equity (Noncontrolling Interest

Equity (Noncontrolling Interest - Narrative) (Details) - Jun. 30, 2015 - Class B Units [Member] - shares	Total
Class of Stock [Line Items]
Shares retained by former owners (in shares)	100
First Target Distribution [Member]
Class of Stock [Line Items]
Increasing distribution percentage associated with Class B Units	15.00%
Second Target Distribution [Member]
Class of Stock [Line Items]
Increasing distribution percentage associated with Class B Units	25.00%
Third and Thereafter Target Distribution [Member]
Class of Stock [Line Items]
Increasing distribution percentage associated with Class B Units	50.00%

(Allocation of Distributions) (

(Allocation of Distributions) (Details) - 6 months ended Jun. 30, 2015 - USD ($)	Total
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 - N

Equity (Equity Compensation - Narrative) (Details) - USD ($) $ in Millions	Jun. 26, 2014	Mar. 31, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense		$ 0.4	$ 0.4	$ 4.3	$ 0.6
Phantom Units [Member] | Common Units [Member] | Early Vesting [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense		$ 0.9
Phantom Units [Member] | Common Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units granted (in units)	432,038
Value of phantom units granted	$ 10.1
Maximum [Member] | Phantom Units [Member] | Common Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom unit vesting period	2 years
Service Requirement Units [Member] | Phantom Units [Member] | Common Units [Member] | EFS and RPS [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Phantom units granted (in units)	401,171
Fair Market Value Purchase Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units granted (in units)		242,753
Common units vested (in units)		219,439
Equity-based compensation expense				$ 1.5

Cumulative Convertible Prefer69

Cumulative Convertible Preferred Units (Narrative) (Details)	Jun. 18, 2015$ / shares	Jun. 02, 2015USD ($)shares	May. 08, 2015USD ($)$ / shares	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)
Temporary Equity [Line Items]
Estimated offering costs						$ 0	$ 100,000
distributions on Series A Preferred Units				$ 988,000	$ 0	988,000	$ 0
Series A Cumulative Convertible Preferred Units [Member]
Temporary Equity [Line Items]
Public offering of units			$ 44,000,000
Unit price (in usd per unit) | $ / shares			$ 25
Option period for underwriters to purchase additional units			30 days
Additional units available to underwrites (in shares) | shares		264,000
Conversion ratio of preferred units			3.7821
Distribution rate			11.00%
Transfer treshold						$ 100,000,000
Increase in distribution rate			2.00%
Majority voting threshold						66.67%
Proceeds from public offering			$ 44,400,000
Underwriting discounts			2,900,000
Estimated offering costs			$ 1,000,000
Additional units issued (in units) | shares		170,000
Proceeds from issuance of Series A preferred units		$ 4,000,000
Distribution declared on preferred units (in usd per unit) | $ / shares	$ 0.5118
Maximum [Member] | Series A Cumulative Convertible Preferred Units [Member]
Temporary Equity [Line Items]
Distribution rate			20.00%

Earnings per Unit (Schedule of

Earnings per Unit (Schedule of Earnings Per Unit) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015		Jun. 30, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (109,856)	$ 1,586	$ (167,028)		$ 54
Common Stock Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (97,513)	$ 1,334	$ (147,068)		$ 97
Weighted average units outstanding (in units)	16,458,000	12,529,000	16,402,000		11,232,000
Basic and diluted income per unit (in usd per unit)	$ (5.92)	$ 0.11	$ (8.97)		$ 0.01
Subordinated Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss	$ (13,506)	$ 235	$ (20,653)		$ (40)
Weighted average units outstanding (in units)	2,205,000	2,205,000	2,205,000		2,205,000
Basic and diluted income per unit (in usd per unit)	$ (6.12)	$ 0.11	$ (9.37)		$ (0.02)
General Partnership Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss		$ 17	$ (470)	[1]	$ (3)
Weighted average units outstanding (in units)		155,000	155,000	[1]	155,000
Basic and diluted income per unit (in usd per unit)		$ 0.11	$ (3.03)	[1]	$ (0.02)
Series A Cumulative Convertible Preferred Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities (in units)	4,074,693		2,048,603
LTIP Awards [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities (in units)	33,714		34,873
[1]	General partner units were converted to common units effective April 27, 2015. Net loss and per unit loss reflected is the loss allocated to general partner units prior to the conversion.

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	Apr. 27, 2015USD ($)	Feb. 24, 2015USD ($)	Jan. 09, 2015USD ($)parcel	Apr. 30, 2015shares	Jun. 30, 2015USD ($)shares	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)shares	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Apr. 01, 2015	Jan. 12, 2015
Related Party Transaction [Line Items]
Leasehold cost obligations					$ 200		$ 200		$ 400
General and administrative expense					$ 6,671	$ 3,489	18,905	$ 9,050
General Partner [Member]
Related Party Transaction [Line Items]
General and administrative expense						$ 300		$ 600
Professional fees paid							$ 400		2,300
Board of Directors Chairman [Member]
Related Party Transaction [Line Items]
Ownership percentage of reporting company										25.00%
Percentage of common stock owned					15.10%		15.10%				15.60%
Percentage of subordinate units owned					100.00%		100.00%
NSEC [Member]
Related Party Transaction [Line Items]
Ownership percentage of reporting company										5.60%
Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Percentage of common stock owned										6.40%
New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related party receivables					$ 5,700		$ 5,700		3,400
General Partner [Member]
Related Party Transaction [Line Items]
Units converted (in units) | shares				155,102
General Partner [Member] | Chief Executive Officer [Member]
Related Party Transaction [Line Items]
Ownership percentage of reporting company										69.40%
Subordinated Units [Member] | Board of Directors Chairman [Member]
Related Party Transaction [Line Items]
Number of subordinate units owned | shares					2,205,000		2,205,000
MCCS [Member]
Related Party Transaction [Line Items]
Liability assumed in acquisition									$ 700
Deylau [Member] | General Partner [Member]
Related Party Transaction [Line Items]
Transfer of ownership presented as percentage of general partner ownership interest	18.40%
Sale of oil and gas assets to subsidiary	$ 150,000
MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired | parcel			2
Sales of real property			$ 900
2100 Energy LLC [Member] | General Partner [Member]
Related Party Transaction [Line Items]
Transfer of ownership presented as percentage of general partner ownership interest	69.40%
Canadian County, OK [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired | parcel			1
Ector County, TX [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired | parcel			1
Karnes, Texas [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Sales of real property		$ 500
President [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Ownership percentage			50.00%
President [Member] | MidCentral Energy Services [Member] | Karnes, Texas [Member]
Related Party Transaction [Line Items]
Ownership percentage		33.00%
Chief Executive Officer [Member] | MidCentral Energy Services [Member]
Related Party Transaction [Line Items]
Number of parcels of real estate acquired | parcel			3
Ownership percentage			50.00%
Real estate land, carrying value		$ 600
Chief Executive Officer [Member] | MidCentral Energy Services [Member] | Karnes, Texas [Member]
Related Party Transaction [Line Items]
Ownership percentage		67.00%

Related Party Transactions (Sum

Related Party Transactions (Summary of Related Party Transactions) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Related Party Transaction [Line Items]
Related Party Costs	$ 1,083	$ 936	$ 2,098	$ 1,735
Producing Overhead Charges [Member] | New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related Party Costs	639	454	1,372	829
Drilling And Completion Overhead Charges [Member] | New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related Party Costs	138	39	176	48
Saltwater Disposal Fees [Member] | New Dominion LLC [Member]
Related Party Transaction [Line Items]
Related Party Costs	$ 306	$ 443	$ 550	$ 858

Property, Plant and Equipment73

Property, Plant and Equipment (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Property, Plant and Equipment [Line Items]
Impairment	$ 99,689		$ 0	$ 142,808	$ 0
Oil and Gas Properties
Property, Plant and Equipment [Line Items]
Impairment	32,900	$ 43,100
Oilfield Services [Member] | Equipment
Property, Plant and Equipment [Line Items]
Impairment	$ 6,300			$ 6,300

Property, Plant and Equipment74

Property, Plant and Equipment (Schedule of Property and Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property and equipment, net	$ 68,418	$ 68,886
Oilfield Services [Member]
Property, Plant and Equipment [Line Items]
Total	83,162	73,659
Less: accumulated depreciation and impairment	(15,945)	(4,773)
Property and equipment (excluding land), net	67,217	68,886
Land	1,201	0
Property and equipment, net	68,418	68,886
Oilfield Services [Member] | Vehicles and Transportation Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	15,970	15,891
Oilfield Services [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	51,680	44,441
Oilfield Services [Member] | Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total	2,036	1,069
Oilfield Services [Member] | Iron [Member]
Property, Plant and Equipment [Line Items]
Total	$ 13,476	$ 12,258

Commitments and Contingencies (

Commitments and Contingencies (Details) - USD ($)	Jan. 29, 2015	Jun. 30, 2015	Mar. 31, 2015	Jan. 12, 2015	Dec. 31, 2014	Jun. 26, 2014
Loss Contingencies [Line Items]
Contingent consideration, net		$ 22,000,000
Estimated contingency loss		250,000
Pending Litigation [Member]
Loss Contingencies [Line Items]
Pending litigation, amount	$ 1,900,000
MidCentral Energy Services [Member]
Loss Contingencies [Line Items]
Contingent consideration		4,100,000
MCCS [Member]
Loss Contingencies [Line Items]
Contingent consideration		6,300,000				$ 4,057,000	[1]
EFS and RPS [Member]
Loss Contingencies [Line Items]
Contingent consideration		$ 22,000,000			$ 23,300,000	21,984,000	[2]
Interest rate			5.50%
Percentage of contingent consideration to be paid in cash		50.00%
Receivable due from prior owners		$ 1,000,000
Percentage of contingent consideration to be paid in common units		50.00%
Maximum [Member] | MCCS [Member]
Loss Contingencies [Line Items]
Contingent consideration						$ 4,500,000
Board of Directors Chairman [Member]
Loss Contingencies [Line Items]
Percentage of common stock owned		15.10%		15.60%
Affiliated Entity [Member]
Loss Contingencies [Line Items]
Percentage of common stock owned				30.60%
[1]	The Partnership agreed to provide additional common units in the second quarter of 2015 to the former owners of MCCS based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended 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 14 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.
[2]	The Partnership agreed to provide additional consideration in the second quarter of 2015 to the former owners of EFS and RPS 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 at the acquisition date through the use of a probability analysis. See Note 14 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.

Asset Retirement Obligations (C

Asset Retirement Obligations (Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at January 1, 2015			$ 3,681
Liability incurred upon acquiring and drilling wells			0
Accretion	$ 59	$ 74	133	$ 143
Asset retirement obligation at June 30, 2015	3,814		3,814
Less current portion	117		117
Asset retirement obligations, net of current	$ 3,697		$ 3,697		$ 3,568

Business Segment Information (D

Business Segment Information (Details)	6 Months Ended
	Jun. 30, 2015segment
Segment Reporting [Abstract]
Number of operating segments	2

Business Segment Information (S

Business Segment Information (Summary of Segment Operating Activities) (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015		Jun. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Revenue	$ 24,084		$ 26,818		$ 62,201		$ 54,245
Direct operating expenses	18,729		11,276		46,154		21,224
Segment margin	5,355		15,542		16,047		33,021
Depreciation, depletion, amortization and accretion	6,058		10,363		18,479		19,710
Impairment	99,689		0		142,808		0
General and administrative	6,671		3,489		18,905		9,050
Operating (loss) income	(107,063)		1,690		(164,145)		4,261
Capital expenditures	140	[1]	9,886	[1]	7,257	[2]	21,451
Total assets	204,758				204,758			$ 375,546
Operating Segments [Member] | Exploration and Production [Member]
Segment Reporting Information [Line Items]
Revenue	5,319		16,718		11,886		35,569
Direct operating expenses	4,092		5,308		8,458		10,690
Segment margin	1,227		11,410		3,428		24,879
Depreciation, depletion, amortization and accretion	3,620		6,970		8,413		12,857
Impairment	32,905				76,024
General and administrative	2,254		2,022		6,823		5,866
Operating (loss) income	(37,552)		2,418		(87,832)		6,156
Capital expenditures	126	[1]	7,709	[1]	1,140	[2]	18,460
Total assets	111,793				111,793			199,178
Operating Segments [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Revenue	18,765		10,100		50,315		18,676
Direct operating expenses	14,637		5,968		37,696		10,534
Segment margin	4,128		4,132		12,619		8,142
Depreciation, depletion, amortization and accretion	2,438		3,393		10,066		6,853
Impairment	66,784				66,784
General and administrative	4,417		1,467		12,082		3,184
Operating (loss) income	(69,511)		(728)		(76,313)		(1,895)
Capital expenditures	14	[1]	$ 2,177	[1]	6,117	[2]	$ 2,991
Total assets	$ 92,965				$ 92,965			$ 176,368
[1]	On an accrual basis and exclusive of acquisitions.
[2]	On an accrual basis and exclusive of acquisitions.

Uncategorized Items - nslp-2015

Label	Element	Value
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	us-gaap_DerivativeInstrumentsNotDesignatedAsHedgingInstrumentsGainLossNet	$ (1,067)
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	us-gaap_DerivativeInstrumentsNotDesignatedAsHedgingInstrumentsGainLossNet	(1,396)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	(109,856)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	us-gaap_ProfitLoss	1,586
Depreciation, Depletion and Amortization	us-gaap_DepreciationDepletionAndAmortization	10,289
Depreciation, Depletion and Amortization	us-gaap_DepreciationDepletionAndAmortization	5,999
Temporary Equity, Accretion to Redemption Value, Adjustment	us-gaap_TemporaryEquityAccretionToRedemptionValueAdjustment	0
Temporary Equity, Accretion to Redemption Value, Adjustment	us-gaap_TemporaryEquityAccretionToRedemptionValueAdjustment	$ 175