10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

(MARK ONE)

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2014

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________.

Commission File Number: 001-35809

NEW SOURCE ENERGY PARTNERS L.P.
(Exact name of registrant as specified in its charter)
Delaware	38-3888132
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
914 North Broadway, Suite 230 Oklahoma City, Oklahoma	73102
(Address of principal executive offices)	(Zip Code)
(Registrant’s telephone number, including area code):  (405) 272-3028

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports),

and (2) has been subject to such filing requirements for the past 90 days. Yes☑ No☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ☐	Accelerated filer ☐	Non-accelerated filer ☑	Smaller reporting company ☐
	(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of November 3, 2014, the registrant had 16,160,381 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.

NEW SOURCE ENERGY PARTNERS L.P.

Form 10-Q

Quarter Ended September 30, 2014

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)	5
		Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	5
		Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2014 and 2013	6
		Condensed Consolidated Statement of Unitholders' Equity for the nine months ended September 30, 2014	7
		Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2014 and 2013	8
		Notes to Condensed Consolidated Financial Statements	10
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	50
	Item 4.	Controls and Procedures	53
PART II – OTHER INFORMATION			54
	Item 1.	Legal Proceedings	54
	Item 1A.	Risk Factors	55
	Item 6.	Exhibits	55

2

CERTAIN DEFINED TERMS

As used in this Quarterly Report on Form 10-Q, unless otherwise indicated, the following terms have the following meanings:

• "general partner" refers to New Source Energy GP, LLC, our general partner;

• "IPO Properties" refers to the properties, producing wells, and related oil and natural gas interests that were contributed to us by New Source Energy Corporation in connection with our initial public offering;

• "MCE" or "MCE Entities" refers collectively to MCE, LP and MCE GP, LLC;

• "New Dominion" refers to New Dominion, LLC, the entity that serves as our contract operator and provides certain operational services to us;

• "NSEC" refers to New Source Energy Corporation, an independent energy company engaged in the development and production of onshore oil and liquids-rich natural gas projects in the United States;

• "NGL" refers to natural gas liquids;

• "our management," "our employees," or similar terms refer to the management and personnel of our general partner who perform managerial and administrative services on our behalf;

• "Partnership," "we," "our," "us," and like terms refer collectively to New Source Energy Partners L.P. and its subsidiaries; and

• "Scintilla" refers to Scintilla, LLC, the entity from which NSEC acquired substantially all of its assets in August 2011.

3

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q ("Quarterly Report") of the Partnership includes "forward-looking statements" within the meaning of federal securities laws. These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, the Partnership’s liquidity, capital resources, debt profile, acquisitions and the effects thereof on the Partnership's financial condition, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Partnership’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, and other statements concerning the Partnership’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as "estimate," "assume," "target," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "foresee," "plan," "goal," "should," "intend" or other words that convey the uncertainty of future events or outcomes. The Partnership has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Partnership in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Partnership believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Partnership’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Partnership disclaims any obligation to update or revise these forward-looking statements unless required by law, and it cautions readers not to rely on them unduly. While the Partnership’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in "Risk Factors" in Item 1A of Part II of this Quarterly Report and in "Risk Factors" in Item 1A of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (the "2013 Form 10-K").

4

PART I: Financial Information

ITEM 1. Financial Statements

New Source Energy Partners L.P.

Condensed Consolidated Balance Sheets

(Unaudited)

	September 30, 2014			December 31, 2013
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash	$	5,696		$	7,291
Restricted cash	25			—
Accounts receivable	40,492			12,609
Other current assets	7,867			1,114
Total current assets	54,080			21,014
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	329,864			291,829
Less: Accumulated depreciation, depletion, and amortization	(148,427		)	(128,961		)
Total oil and natural gas properties, net	181,437			162,868
Property and equipment, net	63,281			8,166
Intangible assets, net	89,813			35,009
Goodwill	43,534			23,974
Other assets	2,379			3,679
Total assets	$	434,524		$	254,710
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	12,636		$	3,267
Accounts payable-related parties	5,103			8,221
Factoring payable	15,526			1,907
Contingent consideration payable	36,854			—
Derivative contracts	608			3,167
Current portion of long-term debt	21,132			719
Total current liabilities	91,859			17,281
Long-term debt	96,301			80,014
Contingent consideration payable to related parties	—			6,320
Asset retirement obligations	3,877			3,455
Other liabilities	396			387
Total liabilities	192,433			107,457
Commitments and contingencies (Note 14)
Unitholders' equity:
Common units (15,440,381 units issued and outstanding at September 30, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	257,876			151,773
Common units held in escrow	(8,227		)	—
Subordinated units (2,205,000 units issued and outstanding at September 30, 2014 and December 31, 2013)	(21,582		)	(17,334		)
General partner's units (155,102 units issued and outstanding at September 30, 2014 and December 31, 2013)	(1,473		)	(1,174		)
Total New Source Energy Partners L.P. unitholders' equity	226,594			133,265
Noncontrolling interest	15,497			13,988
Total unitholders' equity	242,091			147,253
Total liabilities and unitholders' equity	$	434,524		$	254,710

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

5

New Source Energy Partners L.P.

Condensed Consolidated Statements of Operations

(Unaudited)

	Three Months Ended   September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands, except per unit amounts)
Revenues:
Oil sales	$	3,798		$	2,044		$	12,146		$	4,879
Natural gas sales	3,711			2,582			12,928			7,031
NGL sales	8,052			7,805			26,056			20,530
Oilfield services	40,863			—			59,539			—
Total revenues	56,424			12,431			110,669			32,440
Operating costs and expenses:
Oil, natural gas and NGL production	4,894			3,428			13,913			8,702
Production taxes	668			557			2,339			1,996
Cost of providing oilfield services	24,315			—			34,849			—
Depreciation, depletion and amortization	17,760			4,913			37,329			11,686
Accretion	77			59			219			145
General and administrative	13,785			1,353			22,835			11,452
Total operating costs and expenses	61,499			10,310			111,484			33,981
Operating (loss) income	(5,075		)	2,121			(815		)	(1,541		)
Other income (expense):
Interest expense	(1,458		)	(654		)	(3,442		)	(3,220		)
Gain (loss) on derivative contracts, net	3,768			(3,453		)	(760		)	(2,597		)
Gain on investment in acquired business	—			—			2,298			—
Other income	11			—			18			—
Loss before income taxes	(2,754		)	(1,986		)	(2,701		)	(7,358		)
Income tax benefit	—			—			—			12,126
Net (loss) income	(2,754		)	(1,986		)	(2,701		)	4,768
Less: net income attributable to noncontrolling interest	242			—			242			—
Net (loss) income attributable to New Source Energy Partners L.P.	$	(2,996	)	$	(1,986	)	$	(2,943	)	$	4,768
Net income prior to purchase of properties from NSEC on February 13, 2013										$	5,303
Net loss subsequent to purchase of properties from NSEC on February 13, 2013 and allocable to units	$	(2,996	)	$	(1,986	)	$	(2,943	)	$	(535	)
Net loss per unit:
Net loss per general partner unit	$	(0.17	)	$	(0.22	)	$	(0.19	)	$	(0.19	)
Net loss per subordinated unit	$	(0.17	)	$	(0.22	)	$	(0.19	)	$	(0.20	)
Net loss per common unit	$	(0.17	)	$	(0.22	)	$	(0.20	)	$	(0.01	)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.  

6

New Source Energy Partners L.P.

Condensed Consolidated Statement of Unitholders' Equity

For the Nine Months Ended September 30, 2014

(Unaudited)

	Common				Subordinated				General Partner				Non-controlling Interest			Total Unitholders' Equity
	Units	Equity			Units	Equity			Units	Equity
	(in thousands, except unit amounts)
Balance, December 31, 2013	9,599,578	$	151,773		2,205,000	$	(17,334	)	155,102	$	(1,174	)	$	13,988		$	147,253
Issuance of common units, net of offering costs	3,450,000	76,191			—	—			—	—			—			76,191
Offering cost related to 2013 private placement paid in 2014	—	(100		)	—	—			—	—			—			(100		)
Issuance of common units in acquisitions	1,964,957	43,938			—	—			—	—			1,509			45,447
Equity-based compensation	425,846	1,906			—	—			—	—			—			1,906
Distributions to unitholders	—	(21,556		)	—	(3,837		)	—	(270		)	(242		)	(25,905		)
Net (loss) income	—	(2,503		)	—	(411		)	—	(29		)	242			(2,701		)
Balance, September 30, 2014	15,440,381	$	249,649		2,205,000	$	(21,582	)	155,102	$	(1,473	)	$	15,497		$	242,091

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

7

New Source Energy Partners L.P.  Condensed Consolidated Statements of Cash Flows (Unaudited)
	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Cash Flows from Operating Activities:
Net (loss) income	$	(2,701	)	$	4,768
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	37,329			11,686
Accretion	219			145
Amortization of deferred loan costs	451			358
Write off of loan costs due to debt refinancing	—			1,436
Equity-based compensation	1,906			7,738
Deferred income tax benefit	—			(12,023		)
Change in fair value of contingent consideration	4,493			—
Gain on investment in acquired business	(2,298		)	—
Loss on derivative contracts, net	760			2,597
Cash paid on settlement of derivative contracts	(3,750		)	(878		)
Payments for premiums on derivatives	—			(1,334		)
Changes in operating assets and liabilities:
Accounts receivable	(4,533		)	(9,673		)
Other current assets and other assets	(3,582		)	(160		)
Accounts payable and accrued liabilities	(1,893		)	5,020
Net cash provided by operating activities	26,401			9,680
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	(63,446		)	(15,957		)
Additions to oil and natural gas properties	(20,845		)	(18,261		)
Additions to other property and equipment	(6,726		)	—
Net cash used in investing activities	(91,017		)	(34,218		)
Cash Flows from Financing Activities:
Proceeds from borrowings	22,544			69,500
Payments on borrowings	(8,401		)	(95,000		)
Bank overdraft	281			—
Proceeds from financing	527			—
Proceeds from borrowings, net - related party	300			—
Payments for deferred loan costs	(437		)	(1,762		)
Payments on factoring payable, net	(2,221		)	—
Proceeds from sales of common units, net of offering costs	76,191			77,880
Payments of offering costs	(100		)	—
Distribution to unitholders	(25,663		)	(7,527		)
Distribution to NSEC	—			(18,295		)
Net cash provided by financing activities	63,021			24,796
Net change in cash and cash equivalents	(1,595		)	258
Cash and cash equivalents, beginning of period	7,291			—
Cash and cash equivalents, end of period	$	5,696		$	258

New Source Energy Partners L.P.  Condensed Consolidated Statements of Cash Flows, Continued (Unaudited)
Supplemental Cash Flow Information:
Cash paid for interest	$	2,999		$	1,476
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation	$	203		$	1,403
Decrease in accrued capital expenditures	$	(1,561	)	$	(258	)
Accounts receivable distributed to NSEC	$	—		$	(7,014	)
Accounts payable assumed by NSEC	$	—		$	(1,742	)
Subordinated note issued to NSEC for oil and natural gas properties	$	—		$	25,000
Distribution payable	$	242		$	—
Common units issued in connection with acquisitions	$	(46,239	)	$	(27,983	)
Acquisition of property and equipment by financing	$	6,707		$	—
Factoring payables assumed in connection with acquisitions	$	15,840		$	—
Debt assumed in connection with acquisitions	$	17,571		$	—

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.  Basis of Presentation

Nature of Business.  We are a vertically integrated independent energy partnership formed in October 2012. The Partnership is engaged in the development and 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, the Partnership is engaged in oilfield services through its oilfield services subsidiaries. Our oilfield services business provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, throughout the Mid-Continent region and in South Texas and West Texas. In June 2014, we acquired oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry primarily in Oklahoma, Texas, Pennsylvania and Ohio.

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, 2013 have been derived from the audited financial statements contained in the Partnership’s 2013 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2013 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s 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 2013 Form 10-K.

Significant Accounting Policies. For a description of the Partnership’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2013 Form 10-K.

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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed and asset retirement obligations. Actual results could differ from those estimates.

Recently Issued Accounting Standard. In May 2014, the Financial Accounting Standards Board 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. ASU 2014-09 is effective for fiscal years beginning after December 15, 2016 and is to be applied retrospectively. Early application is not permitted. We are in the process of assessing the potential impact of ASU 2014-09 on the Partnership's financial statements.

10

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

2.  Acquisitions

The Partnership completed acquisitions during 2013 and 2014, as described below. Certain of the 2013 acquisitions increased the Partnership's portfolio of oil and natural gas properties. The acquisitions of MCE, Erick Flowback Services LLC ("EFS"), Rod's Production Services, L.L.C. ("RPS") and MidCentral Completion Services, LLC ("MCCS") established the Partnership's oilfield services segment, which helps to facilitate the Partnership's goals of becoming a more fully integrated oil and natural gas partnership. With the exception of the acquisition of oil and natural gas properties from Orion Exploration Partners, LLC, all of the 2013 acquisitions were with related parties. The acquisition of MCCS was the only acquisition in 2014 with related parties. See Note 11 "Related Party Transactions."

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy as described in Note 7 "Fair Value Measurements." Fair value may be estimated using comparable market data, a discounted cash flow method, or another method as discussed below. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of applicable sales estimates, operational costs and a risk-adjusted discount rate. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. Fair value of MCCS' inventory acquired was determined based on a comparative sales approach. Fair value for intangible assets acquired was primarily determined using a discounted cash flow model or multi-period excess earnings model under the income approach, which factors in discount rates, probability factors and forecasts. The fair values of property, plant and equipment acquired were primarily based on a cost approach using an indirect cost methodology to determine replacement cost. The inputs, as noted above, used to determine fair value required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Carrying value for current assets and liabilities acquired is typically representative of fair value due to their short term nature.

2013 Acquisitions

March Acquired Properties.In March 2013, we acquired certain oil and natural gas properties located in the Golden Lane and Luther fields in Oklahoma from New Source, Scintilla, and W.K. Chernicky, LLC, for an aggregate adjusted purchase price of approximately $28.0 million (the "March Acquired Properties"). As consideration, the Partnership issued 1,378,500 common units valued at $20.30 per unit.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	29,049
Other assets	754
Asset retirement obligations	(1,333		)
Other liabilities	(488		)
Total net assets	$	27,982

May Acquired Properties.In May 2013, the Partnership completed an acquisition of certain oil and natural gas properties located in Oklahoma from NSEC for approximately $7.9 million, net of purchase price adjustments (the "May Acquired Properties").

11

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	8,165
Asset retirement obligations	(19		)
Other liabilities	(254		)
Total net assets	$	7,892

July Scintilla Acquired Properties.In July 2013, the Partnership completed an acquisition of a 10% working interest in certain oil and natural gas properties located in Oklahoma from Scintilla for approximately $4.9 million, net of purchase price adjustments.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	4,888
Asset retirement obligations	(4		)
Other liabilities	(18		)
Total net assets	$	4,866

Orion Acquired Properties.In July 2013, the Partnership acquired certain oil and natural gas properties located in Oklahoma from Orion Exploration Partners, LLC for approximately $3.2 million, net of purchase price adjustments.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	3,274
Asset retirement obligations	(24		)
Other liabilities	(20		)
Total net assets	$	3,230

The amounts of revenues and excess of revenues over direct operating expenses included in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013 generated by the March Acquired Properties, the May Acquired Properties, the July Scintilla Acquired Properties and the Orion Acquired Properties are shown in the table below. Direct operating expenses include lease operating expenses and production taxes.

	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
	(in thousands)
Revenue	$	4,197	$	6,974
Excess of revenues over direct operating expenses	$	2,180	$	3,350

Acquisition expense related to the acquisitions as of September 30, 2013 of $0.5 million and $1.0 million were included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013, respectively.

12

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Southern Dome Acquired Properties.In October 2013, the Partnership completed the acquisition of working interests in 25 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma (the "Southern Dome Acquired Properties") from Scintilla for total consideration of $14.5 million, net of purchase price adjustments.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Consideration:
Cash	$	4,260
Fair value of common units granted (1)	8,608
Contingent consideration (2)	1,600
Total fair value of consideration	$	14,468
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	15,190
Asset retirement obligations	(170		)
Other liabilities	(552		)
Total net assets	$	14,468

__________

(1) The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).

(2) The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideration.

MCE Acquisition.In November 2013, the Partnership acquired 100% of the equity interests in MCE, other than Class B Units that were retained by certain of the sellers as discussed further below (the "MCE Acquisition"). MidCentral Energy Services, LLC ("MCES"), a wholly owned subsidiary of MCE, operates an oilfield services business that offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region and in South Texas and West Texas, along with the rental of certain ancillary equipment necessary to perform such services.

Total consideration for the MCE Acquisition is as follows (in thousands):

Consideration:
Cash	$	3,781
Fair value of common units granted (1)	41,822
Common units granted to MCE employees (2)	2,259
Contingent consideration (3)	6,320
MCE Class B units granted (4)	13,988
Total fair value of consideration	$	68,170

__________

(1) The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).

(2) The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnership’s long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.

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

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(Unaudited)

(4) Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See Note 9 "Equity" for additional discussion of these incentive distributions. The Class B units were valued at $14.0 million at the acquisition date through the use of a Monte Carlo simulation.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	1,522
Accounts receivable	3,365
Other current assets	954
Property and equipment	7,923
Intangible asset (1)	36,772
Goodwill (2) (3)	24,077
Other assets	19
Total assets acquired	74,632
Accounts payable and accrued liabilities (3)	(2,448		)
Factoring payable	(1,679		)
Long-term debt	(2,335		)
Total liabilities assumed	(6,462		)
Net assets acquired	$	68,170

__________

(1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

(2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.

(3) Includes purchase price allocation adjustment of $0.1 million made during the three months ended September 30, 2014 based on additional information received on accounts payable assumed.

Since the President and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos, through his control over the Partnership’s general partner, controls the Partnership and also owned 36% of the equity interest in MCE, the MCE Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 36% equity interest in MCE acquired from Mr. Kos at his equity method carrying basis, which was $1.8 million as of November 12, 2013. The Partnership remeasured the 36% interest to determine the acquisition-date fair value and recognized a corresponding gain of $22.7 million on investment in acquired business.

2014 Acquisitions

CEU Acquisition.On January 31, 2014, we completed the acquisition of working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma, from CEU Paradigm, LLC ("CEU") for approximately $17.1 million, net of purchase price adjustments (the "CEU Acquisition").

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(Unaudited)

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition, net of purchase price adjustments, is as follows (in thousands):

Consideration:
Cash	$	5,503
Fair value of common units granted (1)	11,621
Contingent consideration (2)	—
Total fair value of consideration	$	17,124
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	17,306
Asset retirement obligations	(182		)
Total net assets	$	17,124

__________

(1) The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition).

(2) The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period (the "CEU Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

MCCS Acquisition. On June 26, 2014, we exercised the option granted in connection with the MCE Acquisition to acquire 100% of the equity interest in MCCS, an oilfield services company that specializes in providing services, primarily installation and pressure testing, to oil and natural gas exploration and production companies (the "MCCS Acquisition").

Total consideration for the MCCS Acquisition is as follows (in thousands):

Consideration:
Fair value of common units granted (1)	$	789
Contingent consideration (2)	4,057
Noncontrolling interest (3)	1,509
Total fair value of consideration	$	6,355

__________

(1) The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition).

(2) The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 3 "Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

(3) As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.

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The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	109
Accounts receivable	524
Inventory	2,035
Other current assets	14
Property and equipment	107
Intangible asset (1)	1,700
Goodwill (2)	4,060
Other assets	28
Total assets acquired	8,577
Accounts payable and accrued liabilities	(1,431		)
Long-term debt	(791		)
Total liabilities assumed	(2,222		)
Net assets acquired	$	6,355

__________

(1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

(2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS's business. Goodwill has been allocated to the oilfield services segment.

Since the President and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos, through his control over the Partnership’s general partner, controls the Partnership and also owned 50% of the equity interest in MCCS, the MCCS Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 50% equity interest in MCCS acquired from Mr. Kos at his equity method carrying basis, which was $0.1 million as of June 26, 2014. The Partnership remeasured the 50% interest to determine the acquisition-date fair value and recognized a corresponding gain of $2.3 million on investment in acquired business.

Services Acquisition.On June 26, 2014, the Partnership acquired 100% of the outstanding membership interests in EFS and 100% of the outstanding membership interests in RPS for total consideration of approximately $113.2 million (the "Services Acquisition"). EFS and RPS, which are affiliated entities, are oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry.

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(Unaudited)

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 and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition are excluded from consideration based on the future service requirement for vesting. See Note 9 "Equity" for additional discussion of phantom units.

(3) The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 3 "Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. During the three months ended September 30, 2014, a purchase price allocation adjustment was made for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	1,668
Accounts receivable	21,611
Other current assets (1)	620
Property and equipment (1)	43,853
Intangible assets (2)	68,700
Goodwill (1) (3)	15,397
Total assets acquired	151,849
Accounts payable and accrued liabilities (1)	(6,047		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,687		)
Net assets acquired	$	113,162

__________

(1) Includes purchase price allocation adjustments, resulting in an increase totaling $3.7 million to goodwill, during the three months ended September 30, 2014, based on additional information received primarily on other current assets and property and equipment acquired.

(2) 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.

(3) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS

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(Unaudited)

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. During the three months ended, a purchase price allocation adjustment was made to increase the amount assigned to goodwill by approximately $3.7 million, primarily as a result of an increase to the value of the contingent consideration based on additional information made available.

Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the nine months ended September 30, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013. The pro forma combined results of operations for the nine months ended September 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 an acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

	Nine Months Ended September 30, 2014
	(in thousands, except per unit amounts)
Revenue	$	172,590
Net income attributable to New Source Energy Partners L.P. (1)	$	5,084
Net income per common unit (1):
Basic	$	0.31
Diluted	$	0.31

__________

(1) Excludes $24.3 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.

The amounts of revenues and operating income included in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 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 revenue over direct operating expenses and does not reflect certain expenses, such as general and administrative; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. Direct operating expenses include lease operating expenses and production taxes for the CEU Acquisition.

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
	(in thousands)
Revenue	$	30,110	$	35,047
Operating income	$	590	$	2,786

Acquisition expense for the 2014 Material Acquisitions of $0.4 million and $3.6 million were included in general and administrative expenses in the accompanying unaudited statements of operations for the three and nine months ended September 30, 2014, respectively.

The following unaudited pro forma combined results of operations are presented for the three and nine months ended September 30, 2013 as though the Partnership completed the acquisitions of the March Acquired Properties, the Southern Dome Acquired Properties and the MCE Acquisition (collectively, the "2013 Material Acquisitions") as of January 1, 2012, which was the beginning of the earliest period presented at the time of the acquisition, and the 2014 Material Acquisitions, as of January 1, 2013. The pro forma combined results of operations for the three and nine months ended September 30, 2013 have been prepared by adjusting the historical results of the Partnership to include the historical results of these acquisitions through the date of acquisition and estimates of the effect of the 2013 Material Acquisitions and the 2014 Material Acquisitions on the combined results. In addition, pro forma adjustments have been made for the interest that would have been incurred for financing the cash portion of the consideration of the 2013 Material Acquisitions with the Partnership's senior secured revolving credit facility and assume the units issued as consideration for the 2013 Material Acquisitions had been outstanding since January 1, 2012 and the

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(Unaudited)

units issued as consideration for the 2014 Material Acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund an acquisition, had been outstanding since January 1, 2013.

	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
	(in thousands, except per unit amounts)
Revenue	$	65,673		$	136,851
Net loss attributable to New Source Energy Partners L.P. (1)	$	(3,971	)	$	(10,647	)
Net loss per common unit (1):
Basic	$	(0.24	)	$	(0.83	)
Diluted	$	(0.24	)	$	(0.83	)

__________

(1)    Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the nine months ended September 30, 2013.

3. Contingent Consideration

The contingent consideration provided for in certain of our acquisitions represents additional consideration. The fair value of such contingent consideration is estimated using various inputs, including the probability that targets for additional payout will be met, as described below. As the significant inputs to determine fair value of the contingent consideration represent significant unobservable inputs, they are classified as Level 3 under the fair value hierarchy described in Note 7 "Fair Value Measurements."

A reconciliation of the beginning and ending balances of acquisition-related contingent consideration for the three and nine months ended September 30, 2014 is as follows (in thousands):

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Contingent consideration, beginning balance	$	26,609	$	6,320
Acquisition date fair value of contingent consideration - CEU Acquisition	—		—
Acquisition date fair value of contingent consideration - MCCS Acquisition	—		4,057
Acquisition date fair value of contingent consideration - Services Acquisition	4,841		21,984
Change in fair value of contingent consideration	5,404		4,493
Settlement of contingent consideration	—		—
Contingent consideration, ending balance	$	36,854	$	36,854

Southern Dome Contingent Consideration. In conjunction with the acquisition of the Southern Dome Acquired Properties, the Partnership agreed to provide additional consideration to Scintilla if the average daily production attributable to the Southern Dome Acquired Properties for the nine months ending September 30, 2014 exceeds 383.5 Boe. The contingent consideration was determined to have a fair value of $1.6 million at the acquisition date and was included in the consideration for the Southern Dome Acquired Properties. The Partnership estimated the fair value as of December 31, 2013 at $0. As detailed in the acquisition agreement, the additional consideration was calculated as the value of average daily production for the nine months ending September 30, 2014 less (i) the asset value, (ii) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (iii) revenue attributable to any wells located in a specified project area that were not producing in paying quantities as of the effective date of the acquisition. Any change to the fair value of the contingent consideration was adjusted through earnings due to the factors impacting the ultimate payout. Based on actual production levels for the nine months ending September 30, 2014, no additional consideration is due to Scintilla.

MCE Contingent Consideration. The former owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE, excluding EFS, RPS and MCCS, for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $120.0 million cap. The contingent consideration was valued at $6.3 million at the acquisition date and was included in the consideration for the MCE Acquisition. Any change to the fair value of the contingent consideration is adjusted through earnings. Based on projections for MCE, the

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(Unaudited)

Partnership estimated fair value of the MCE Contingent Consideration as of September 30, 2014 and December 31, 2013 was approximately $15.4 million and $6.3 million, respectively, which is presented as contingent consideration payable in the accompanying unaudited condensed consolidated balance sheets. The increase in fair value of approximately $10.0 million and $9.1 million is included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014, respectively.

CEU Contingent Consideration. In conjunction with the CEU Acquisition, the Partnership agreed to provide additional consideration to CEU if the average daily production attributable to the acquired working interest for the nine months ending September 30, 2014 exceeds 566.0 Boe. The CEU Contingent Consideration was determined to have no value at the acquisition date. As detailed in the acquisition agreement, the additional consideration was calculated as the acquisition value of the production increase less (i) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells located in a specified project area that were not producing in paying quantities as of the effective date of the acquisition. Based on actual production levels for the nine months ending September 30, 2014, no additional consideration is due to CEU.

MCCS Contingent Consideration. The former owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $4.5 million cap. The contingent consideration was valued at $4.1 million at the acquisition date and was included in the consideration for the MCCS Acquisition. Any changes to the fair value of the contingent consideration will be adjusted through earnings. The fair value of the contingent consideration was $0.4 million as of September 30, 2014. The decrease in fair value of approximately $3.7 million is included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014.

EFS/RPS Contingent Consideration. The former owners of EFS and RPS are entitled to receive additional consideration in the form of cash and common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments. The terms of the contribution agreement provide that the additional consideration is to be paid approximately 50% in cash and approximately 50% in common units, consistent with the initial consideration for the Services Acquisition. However, the former owners can elect to receive a larger portion of the payout in common units. The contingent consideration was valued at $22.0 million as of the acquisition date and was included in the consideration for the Services Acquisition. Any change to the fair value of the contingent consideration will be adjusted through earnings. The fair value of the contingent consideration was $21.1 million as of September 30, 2014. The decrease in fair value of approximately $0.9 million is included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014.

4.  Debt

The Partnership's debt consists of the following (in thousands):    

	September 30, 2014		December 31, 2013
Credit facility	$	92,250	$	78,500
Notes payable	21,889		2,233
Line of credit	3,294		—
Total debt	117,433		80,733
Less: current maturities of long-term debt	21,132		719
Long-term debt	$	96,301	$	80,014

Senior Secured Revolving Credit Facility

The Partnership has a senior secured revolving credit facility that is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below, (the "credit facility"). As of September 30, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and

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(Unaudited)

amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of all subsidiaries. The credit facility matures in February 2017.

Additionally, the credit facility contains various covenants and restrictive provisions that, among other things, limit the ability of the Partnership to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. Notwithstanding the foregoing, the credit facility permits the Partnership to make distributions to its common unit holders in an amount not to exceed "available cash" (as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership) if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed 90%. As of September 30, 2014, the Partnership was in compliance with all covenants under the credit facility.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At September 30, 2014 and December 31, 2013, the average annual interest rate on borrowings outstanding under the credit facility was 3.25%. At September 30, 2014, the borrowing base under the credit facility was $102.5 million with $10.25 million of available borrowing capacity and no available borrowing capacity before restriction on distribution occurs. In October 2014, the Partnership repaid $9.25 million in borrowings under the credit facility, which increases the amount of available borrowing capacity before restriction on distribution occurs by $9.25 million.

The semi-annual redetermination of the borrowing base on our credit facility is currently in process. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. Based on our reserve estimates and applicable commodity pricing, we may have a decrease to our borrowing base as a result of the redetermination. As of November 13, 2014, the redetermination of our borrowing base had not been finalized.

Notes Payable

The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. These notes range from 12-60 months in duration with maturity dates from August 2015 through April 2018 and carry variable interest rates ranging from 5.28% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. In August 2014, MCES entered into $3.5 million of additional notes payable. At September 30, 2014, the Partnership had $7.7 million outstanding under the MCES notes payable as of September 30, 2014.

In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on term loans held by EFS. These term loans had a balance of $14.2 million as of September 30, 2014 and mature on June 26, 2015. The term loans have a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at September 30, 2014, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The term loans are collateralized by various assets of the parties to the agreement and guaranteed by MCE and former owners of EFS and RPS. The Partnership is required to maintain a reserve bank account into which the lesser of $0.3 million or 100% of excess cash flow (as defined in the loan agreement) shall be deposited quarterly and used to fund an additional annual payment on September 30th of each year during the term of the loans.

The EFS term loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, beginning October 1, 2014, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0 (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $4.0 million, in each case as more fully described in the loan agreement.

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(Unaudited)

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. Interest only payments are due monthly with the line of credit maturing in February 2015. The line of credit replaced MCES' factoring payable agreement described in Note 5 "Factoring Payable." Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at September 30, 2014. The line of credit is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. Based on the outstanding balance of $3.3 million, there was $0.7 million of available borrowing capacity at September 30, 2014.

The line of credit contained a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of September 30, 2014, MCES was in compliance with this covenant under the line of credit.

5.  Factoring Payable

The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of MCES. At December 31, 2013, the outstanding balance was $1.9 million. The outstanding balance was paid and the agreement was terminated in February 2014 when MCES established its line of credit. See Note 4 "Debt" for discussion of MCES' line of credit.

In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 3% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not collected within 90 days, the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $15.5 million as of September 30, 2014.

6.  Derivative Contracts 

Due to the volatility of commodity prices, the Partnership periodically enters into derivative contracts to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations for a portion of its oil, natural gas and NGL production. While the use of derivative contracts limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and 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.

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At September 30, 2014, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.
Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.
Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the put option and the fixed price.
Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The following tables present our derivative instruments outstanding as of September 30, 2014:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2014	23,763	$	80.00	$	103.50
2015	42,649	$	80.00	$	93.25

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	36,500	$	77.50	$	92.50	$	102.60

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2014	260,751	$	4.00	$	4.41
2015	1,362,382	$	4.00	$	4.32

Oil put options	Volumes (Bbls)	Floor Price
2014	7,418	$	80.00

Natural gas put options	Volumes (MMBtu)	Floor Price
2014	99,034	$	3.50
2015	798,853	$	3.50
2016	930,468	$	3.50

NGL put options	Volumes (Bbls)	Average Floor Price
2014	5,535	$	63.19

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Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	6,900	$	103.52
2015	39,411	$	88.90
2016	36,658	$	86.00

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2014	176,795	$	4.09
2015	800,573	$	4.25
2016	629,301	$	4.37

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	168,924	$	39.44
2015	84,793	$	75.18

By using derivative instruments to mitigate exposures to changes in commodity prices, the Partnership exposes itself to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. The Partnership nets derivative assets and liabilities for counterparties where it has a legal right of offset. Such credit risk is mitigated by the fact that the Partnership's derivatives counterparties are major financial institutions with investment grade credit ratings, some of which are lenders under the Partnership's credit facility.  In addition, the Partnership routinely monitors the creditworthiness of its counterparties.

The following table summarizes our derivative contracts on a gross basis, the effects of netting assets and liabilities for which the right of offset exists (in thousands):

September 30, 2014	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,065	$	(404	)	$	661
Commodity derivatives - long-term assets	565		(6		)	559
Total	$	1,630	$	(410	)	$	1,220
Liabilities:
Commodity derivatives - current liabilities	$	1,012	$	(404	)	$	608
Commodity derivatives - long-term liabilities	43		(6		)	37
Total	$	1,055	$	(410	)	$	645

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December 31, 2013	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,342	$	(1,212	)	$	130
Commodity derivatives - long-term assets	1,638		(978		)	660
Total	$	2,980	$	(2,190	)	$	790
Liabilities:
Commodity derivatives - current liabilities	$	4,379	$	(1,212	)	$	3,167
Commodity derivatives - long-term liabilities	1,015		(978		)	37
Total	$	5,394	$	(2,190	)	$	3,204

See Note 7 "Fair Value Measurements" for additional information on the fair value measurement of the Partnership's derivative contracts.

The following table presents gain (loss) on our derivative contracts as included in the accompanying unaudited statements of operations for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Total gain (loss) on derivative contracts, net (1)	$	3,768	$	(3,453	)	$	(760	)	$	(2,597	)

__________

(1) Included in gain (loss) on derivative contracts for the three months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $0.3 million and $0.5 million, respectively. Included in loss on derivative contracts for the nine months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $3.8 million and $0.9 million, respectively.

7.  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

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forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. The Partnership validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. The Partnership estimates the option value of puts and calls combined into hedges, market prices, contract parameters and discount rates based on published LIBOR rates.

Level 3 Fair Value Measurements

Derivative contracts. The fair values of our natural gas collars, natural gas and NGL put options and NGL fixed price swaps at December 31, 2013 were based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness. The significant unobservable inputs used in the fair value measurement of our natural gas and NGL put options and NGL fixed price swaps were the estimated probability of exercise and the estimate of NGL futures prices. Significant increases (decreases) in the probability of exercise and NGL futures prices could result in a significantly higher (lower) fair value measurement. 

Contingent consideration. As discussed in Note 3 "Contingent Consideration," the Partnership has agreed to pay additional consideration on the MCE Acquisition, the MCCS Acquisition and the Services Acquisition. The fair value of the contingent consideration resulting from these acquisitions is based on the present value of estimated future payments, using various inputs, including forecasted EBITDA metrics and the probability that targets for additional payout will be met. Significant increases (decreases) in the probability of meeting target payout levels could result in a significantly higher (lower) fair value measurement. 

The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis (in thousands):

September 30, 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	$	—	$	157		$	—		$	157
Oil, natural gas and NGL put options	—		539			—			539
Oil, natural gas and NGL fixed price swaps	—		(121		)	—			(121		)
Contingent consideration	—		—			(36,854		)	(36,854		)
Total	$	—	$	575		$	(36,854	)	$	(36,279	)

December 31, 2013	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
Oil collars	$	—	$	(57	)	$	—		$	(57	)
Natural gas collars	—		—			(9		)	(9		)
Oil put options	—		28			—			28
Natural gas and NGL put options	—		—			403			403
Oil and natural gas fixed price swaps	—		132			—			132
NGL fixed price swaps	—		—			(2,911		)	(2,911		)
Contingent consideration	—		—			(6,320		)	(6,320		)
Total	$	—	$	103		$	(8,837	)	$	(8,734	)

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The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended September 30, 2013 and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,			Nine Months Ended September 30,
	2013			2014			2013
Beginning balance	$	1,866		$	(2,517	)	$	(112	)
Loss on derivative contracts	(3,277		)	(2,432		)	(1,522		)
Transfers out (1)	—			2,843			—
Cash paid upon settlement	446			2,106			669
Ending balance	$	(965	)	$	—		$	(965	)
Unrealized losses included in earnings relating to derivatives held at period end	$	(2,677	)	$	—		$	(884	)

__________

(1) Fair values related to the Company’s natural gas collars, natural gas and NGL put options and NGL fixed price swaps were transferred from Level 3 to Level 2 in the second quarter of 2014 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the three and nine months ended September 30, 2013, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

See Note 6 "Derivative Contracts" for additional discussion of our derivative contracts. See Note 3 "Contingent Consideration" for a reconciliation of activity for contingent consideration during the three and nine months ended September 30, 2014.

Fair Value of Financial Instruments

Credit Facility. The carrying amount of the credit facility of $92.25 million and $78.5 million as of September 30, 2014 and December 31, 2013, respectively, approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings.

Notes Payable. The carrying value of our notes payable of $21.9 million and $2.2 million at September 30, 2014 and December 31, 2013 approximated fair value based on rates applicable to similar instruments. 

The credit facility and notes payable are classified as a Level 2 item within the fair value hierarchy.

Fair Value on a Non-Recurring Basis

The Partnership performs valuations on a non-recurring basis primarily as it relates to the consideration, assets acquired, and liabilities assumed related to acquisitions. See Note 2 "Acquisitions" for discussion of these valuations.

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8.  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. Such goodwill is not deductible for tax purposes. Goodwill has been allocated to the oilfield services segment. A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2013 to September 30, 2014 is as follows (in thousands):

Goodwill at December 31, 2013	$	23,974
Additions:
MCCS Acquisition	4,060
Services Acquisition	11,664
Change due to purchase price allocation adjustments (1)	3,836
Goodwill at September 30, 2014	$	43,534

__________

(1)    Includes adjustments totaling $3.8 million during the three months ended September 30, 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. See Note 2 "Acquisitions" for discussion of the purchase price allocation adjustments.

Intangible Assets

Intangible assets were identified in certain of the acquisitions during 2013 and 2014. See Note 2 "Acquisitions" for discussion of our business acquisitions. Intangible assets are amortized over the expected cash flow period for customer relationships and over the agreement period for the non-compete agreements. Amortization expense for the three and nine months ended September 30, 2014 was $9.4 million and $15.6 million, respectively.

The Partnership's intangible assets at September 30, 2014 and December 31, 2013 consist of the following (in thousands):    

	September 30, 2014		December 31, 2013
Customer relationships - MCE Acquisition	$	36,772	$	36,772
Customer relationships - Services Acquisition	64,200		—
Non-compete agreements - Services Acquisition	4,500		—
Customer relationships - MCCS Acquisition	1,700		—
Total intangible assets	107,172		36,772
Less: accumulated amortization	17,359		1,763
Intangible assets, net	$	89,813	$	35,009

9.  Equity

Common Units

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, respectively. See Note 2 "Acquisitions" for additional discussion of these transactions.

Equity Offering. On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million. We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes.

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Distributions

Distributions are declared and distributed within 45 days following the end of each quarter. The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common, subordinated and general partner units during the three and nine months ended September 30, 2014 and 2013, as shown in the following table (in thousands):

Distributions	Common Units		Subordinated Units		General Partner Units		Total
2014
First Quarter (1)	$	4,681	$	1,268	$	89	$	6,038
Second Quarter (2)	$	7,852	$	1,279	$	90	$	9,221
Third Quarter (3)	$	9,025	$	1,290	$	91	$	10,406
2013
Second Quarter (4)	$	1,857	$	604	$	43	$	2,504
Third Quarter (1)	$	3,895	$	1,268	$	89	$	5,252

__________

(1)    Reflects quarterly distributions of $0.575 per unit paid in the third quarter of 2013 and the first quarter of 2014.

(2)    Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014.

(3)    Reflects quarterly distributions of $0.585 per unit paid in the third quarter of 2014.

(4)    Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.

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, second or third quarters of 2014 and 2013 did not exceed the specified targets.

See Note 16 "Subsequent Events" for discussion of distribution declared in October 2014.

Noncontrolling Interest

As part of the MCE Acquisition, certain former owners of MCE retained 100 Class B Units in MCE. The MCE partnership agreement provides that the Class B Units have the right to receive an increasing percentage (15%, 25% and 50%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved based on results of MCES and MCCS. Target distribution levels are adjusted, as applicable and in accordance with the MCE partnership agreement, under certain circumstances. As these Class B Units are not held by the Partnership, they are presented as noncontrolling interest in the accompanying unaudited condensed consolidated financial statements. Any distribution to the Class B Units will be recognized in the period earned and recorded as a reduction to net income attributable to the Partnership.

As a result of the MCCS Acquisition, the specified target distribution levels for the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders were adjusted for the contribution of MCCS to MCE by the Partnership as provided for in the MCE partnership agreement. The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels, as adjusted based on the MCCS Acquisition.

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				Marginal Percentage Interest in  Distributions
	Total Quarterly Distributions per MCE Unit			MCE Class A Unitholders (the Partnership)	MCE Class B Unitholders
Minimum Quarterly Distribution	$16,116			100%	—%
First Target Distribution	$18,533	to	$20,144	85%	15%
Second Target Distribution	$20,145	to	$24,173	75%	25%
Third Target Distribution and Thereafter	$24,174	and above		50%	50%

Based on MCE's distribution amounts, the MCE Class B unitholders were entitled to distributions of approximately $0.2 million for the three months ended September 30, 2014. No distributions were due to the MCE Class B unitholders for the first or second quarter of 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"). Such awards are valued based upon the market value of common units on the date of grant and expensed over the relevant vesting period to the extent the awards contain a service requirement. If there is no service requirement, the awards are expensed at the time of grant. For the three and nine months ended September 30, 2014, the Partnership recorded equity-based compensation expense of $1.3 million and $1.9 million, respectively. For the nine months ended September 30, 2013, the Partnership recorded equity-based compensation expense of $7.7 million. Additionally, the Partnership had $0.4 million of allocated equity-based compensation from NSEC during the nine months ended September 30, 2013. There was no equity-based compensation expense for the three months ended September 30, 2013.

Phantom Units. In conjunction with the Services Acquisition, the Partnership granted 432,038 phantom units, which represent the right to receive common units or cash equal to the value of the associated common units, to employees of EFS and RPS under the FMVPP. The phantom units vest over a period not to exceed 2 years. If a phantom unit is forfeited, the associated common units are released from escrow to an entity owned by the former owners of EFS and RPS. Except as otherwise provided in the Phantom Unit Agreement, phantom units subject to forfeiture restrictions may be forfeited upon termination of employment prior to the end of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the holder until the phantom units vest, the recipients have distribution equivalent rights on these phantom units from the date of grant.

Although the phantom unit grants may be settled in either common units or cash at the holder's election, the settlement of the phantom units upon vesting will be made from a transfer or sale of the associated common units that were issued to an escrow account in conjunction with the Services Acquisition. As a result, the 401,171 phantom units valued at $9.4 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. At September 30, 2014, approximately $8.2 million remains to be expensed. The associated common units held in escrow are reflected as contra equity on the accompanying unaudited condensed consolidated balance sheet at September 30, 2014.

10. Earnings per Unit

The Partnership’s net income is allocated to the common, subordinated and general partner unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the Partnership’s LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. Basic and diluted net income per unit is calculated by dividing net income 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 nine months ended September 30, 2014, LTIP awards of 3,257 and 9,664 common units, respectively, were excluded from the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of September 30, 2013. Therefore, basic and diluted earnings per unit are the same for the three and nine months ended September 30, 2013.

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Basic and diluted earnings per unit for the three and nine months ended September 30, 2014 and 2013 were computed as follows (in thousands, except per unit amounts):

	Three Months Ended   September 30, 2014									Nine Months Ended   September 30, 2014
	Common Units			Subordinated Units			General Partner			Common Units			Subordinated Units			General Partner
Net loss	$	(2,599	)	$	(371	)	$	(26	)	$	(2,503	)	$	(411	)	$	(29	)
Weighted average units outstanding	15,429			2,205			155			12,646			2,205			155
Basic and diluted loss per unit	$	(0.17	)	$	(0.17	)	$	(0.17	)	$	(0.20	)	$	(0.19	)	$	(0.19	)

	Three Months Ended   September 30, 2013									Nine Months Ended   September 30, 2013
	Common Units			Subordinated Units			General Partner			Common Units			Subordinated Units			General Partner
Net loss (1)	$	(1,473	)	$	(479	)	$	(34	)	$	(76	)	$	(430	)	$	(29	)
Weighted average units outstanding	6,774			2,205			155			6,480			2,205			155
Basic and diluted loss per unit	$	(0.22	)	$	(0.22	)	$	(0.22	)	$	(0.01	)	$	(0.20	)	$	(0.19	)

__________

(1) Reflects net loss from February 13, 2013 through September 30, 2013 for the nine months ended September 30, 2013.

11. Related Party Transactions

Ownership. The Partnership is controlled by the Partnership's general partner, which is owned 69.4% by Kristian Kos, the President and Chief Executive Officer of our general partner, and 25.0% by David J. Chernicky, the former Chairman of the board of directors of our general partner. Mr. Kos beneficially owns approximately 5.3% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through Deylau, LLC, an entity he controls. As of September 30, 2014, Mr. Chernicky beneficially owned approximately 17.2% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through NSEC and Scintilla, entities that he controls. In addition, Mr. Chernicky beneficially owns 100% of the 2,205,000 subordinated units through his control of NSEC. As a result of Mr. Chernicky's ownership of the Partnership and his ownership of all of the membership interests in New Dominion, which operates all of the Partnership's oil and natural gas properties, transactions with New Dominion are deemed to be with a related party.

New Dominion. New Dominion is an exploration and production operator, which is wholly owned by Mr. Chernicky. Pursuant to various development agreements with the Partnership, New Dominion is currently contracted to operate the Partnership’s existing wells. New Dominion has historically performed this service for NSEC. In addition to the various development agreements, the Partnership, along with other working interest owners, is a party to an agreement with New Dominion in which we reimburse New Dominion for our proportionate share of costs incurred to construct a gas gathering system. In return, we own a portion of such gas gathering system, which facilitates the transportation of our production in the Greater Golden Lane field to the gas processing plant.

New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated was approximately $0.4 million as of both September 30, 2014 and December 31, 2013, all of which is classified as a long-term liability in the accompanying unaudited condensed consolidated balance sheets. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.

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Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Producing overhead and supervision charges	$	624	$	464	$	2,080	$	1,277
Drilling and completion supervision charges	60		119		230		246
Saltwater disposal fees	260		329		1,075		502
Total expenses incurred	$	944	$	912	$	3,385	$	2,025

At September 30, 2014 and December 31, 2013, $2.2 million and $1.3 million, respectively, were due to New Dominion for charges and fees under operating agreements and included in accounts payable - related party in the accompanying unaudited condensed consolidated balance sheets.

NSEC. Under an agreement by and among NSEC, the Partnership and our general partner, NSEC provided administrative services for the Partnership from February 13, 2013 through December 31, 2013. For the three and nine months ended September 30, 2013, fees paid for such services were $0.7 million and $1.8 million, respectively, and were included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations.

New Source Energy GP, LLC. Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three and nine months ended September 30, 2014, amounts paid to our general partner for such reimbursements were $0.5 million and $1.1 million, respectively, and were included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations. Additionally, we received approximately $1.5 million and paid approximately $1.2 million to our general partner during the nine months ended September 30, 2014 for operational cash advances. At September 30, 2014 and December 31, 2013, $0.8 million and $0.4 million, respectively, were due to our general partner for reimbursement and included in accounts payable - related party in the accompanying unaudited condensed consolidated balance sheets.

Acquisitions. As described in Note 2 "Acquisitions," we acquired oil and natural gas properties, MCE and MCCS from related parties. As these acquisitions were with related parties, the transactions were subject to approval by the board of directors of the Partnership's general partner, based on the approval and recommendation of its conflicts committee.

As discussed in Note 2 "Acquisitions," Mr. Kos was a 36% owner of MCE prior to the MCE Acquisition. Additionally, Dikran Tourian, President-Oilfield Services Division and member of our general partner's board of directors, was a 36% owner of MCE prior to the MCE Acquisition. In conjunction with the MCE Acquisition, Mr. Kos and Mr. Tourian retained Class B units that are entitled to incentive distributions as discussed in Note 9 "Equity" as well as contingent consideration as discussed in Note 3 "Contingent Consideration." In the third quarter of 2014, the Class B unit distribution targets were met. Distributions of $0.2 million for the Class B unitholders are reflected in accounts payable - related parties in the accompanying unaudited consolidated balance sheet at September 30, 2014.

On June 26, 2014, we exercised our option to acquire MCCS, which was owned by Mr. Kos and Mr. Tourian. See Note 2 "Acquisitions" for discussion of this acquisition and Note 3 "Contingent Consideration" for discussion of the MCCS Contingent Consideration. As part of the acquisition of MCCS, we assumed a payable to an entity owned by Mr. Kos and Mr. Tourian. As of September 30, 2014, $0.7 million was remaining and reflected in accounts payable - related parties in the accompanying unaudited consolidated balance sheet.

Transactions with Chief Financial Officer. The Partnership engaged Finley & Cook, PLLC ("Finley & Cook") to provide various accounting services on our behalf during the nine months ended September 30, 2014. Richard Finley, the Chief Financial Officer of our general partner, is an equity member of Finley & Cook, holding a 31.5% ownership interest. The Partnership paid Finley & Cook approximately $0.06 million and $0.4 million in fees for the three and nine months ended September 30, 2014 respectively. NSEC engaged Finley & Cook to provide various accounting services on our behalf during the year ended December 31, 2013. Fees for such accounting services were included in the amounts paid to NSEC, as discussed above.

32

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

12. 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.

Property and equipment, net.Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):

	September 30, 2014			December 31, 2013
Vehicles and transportation equipment	$	15,317		$	561
Machinery and equipment	38,746			4,757
Office furniture and equipment	472			79
Iron	11,212			2,971
Total	65,747			8,368
Less: accumulated depreciation	(2,466		)	(202		)
Property and equipment, net	$	63,281		$	8,166

13.  Asset Retirement Obligations

A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2013 to September 30, 2014 is as follows (in thousands):

Asset retirement obligation at December 31, 2013	$	3,455
Liability incurred upon acquiring and drilling wells	235
Liability settled or disposed	(32		)
Accretion	219
Asset retirement obligation at September 30, 2014	$	3,877

14. Commitments and Contingencies

Commitments

The Partnership is a party to various agreements under which it has rights and obligations to participate in the acquisition and development of undeveloped properties held and to be acquired by Scintilla and New Dominion. These properties will be held by New Dominion for the benefit of the Partnership pending development of the properties. The Partnership is required by its underlying agreements with New Dominion to pay certain acreage fees to reimburse New Dominion for the cost of the acreage attributable to the Partnership’s working interest when invoiced by New Dominion. The Partnership recognizes an asset and corresponding liability as the acreage costs are incurred by New Dominion. See Note 11 "Related Party Transactions."  The agreements require us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. There are significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements. The agreements also require us to pay New Dominion our proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into a development agreement (the "Development Agreement") with NSEC and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, the Partnership has agreed to maintain an average annual maintenance drilling budget of at least $8.2 million to drill certain of the Partnership’s proved undeveloped locations and maintain the Partnership’s producing wells. As of September 30, 2014, we had incurred $10.5 million towards the annual maintenance drilling budget.

See Note 3 "Contingent Consideration" for discussion of contingencies related to certain acquisitions.

Legal Matters

New Dominion is a defendant in a legal proceeding arising in the normal course of its business, which may impact the Partnership as described below.

33

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

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. The case was originally filed in the District Court of Creek County, Oklahoma and was removed by the defendants to the federal court but was remanded to state court on August 1, 2011. A hearing on the matter was held August 27, 2014 at which Scissortail’s motion to dismiss was granted with prejudice and New Dominion’s motion to dismiss was granted in part.  A hearing date for class certification is expected to be set in November 2014.

Any liability on the part of New Dominion, as 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.

15. Business Segment Information

The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties and its general and administrative expenses include certain costs of our corporate administrative functions and changes in the fair value of contingent consideration obligations related to all acquisitions. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, as well as well testing and flowback services. Our oilfield services segment is the aggregation of multiple operating segments that meet the criteria for aggregation due to the economic similarities as well as the similarities in the nature of the services provided, customers served and industry regulations monitored.

34

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Management evaluates the performance of the Partnership’s business segments based on the excess of revenue over direct operating expenses or segment margin. Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands):

	Exploration and Production			Oilfield Services (1)			Total
Three Months Ended September 30, 2014
Revenues	$	15,561		$	40,863		$	56,424
Direct operating expenses	5,562			24,315			29,877
Segment margin	$	9,999		$	16,548		$	26,547
General and administrative expenses	7,354			6,431			13,785
Depreciation, depletion, amortization and accretion	6,834			11,003			17,837
Loss from operations	$	(4,189	)	$	(886	)	$	(5,075	)
Capital expenditures (2)	$	824		$	3,735		$	4,559
Three Months Ended September 30, 2013
Revenues	$	12,431		$	—		$	12,431
Direct operating expenses	3,985			—			3,985
Segment margin	$	8,446		$	—		$	8,446
General and administrative expenses	1,353			—			1,353
Depreciation, depletion, amortization and accretion	4,972			—			4,972
Income from operations	$	2,121		$	—		$	2,121
Capital expenditures (2)	$	14,745		$	—		$	14,745

__________

(1) The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion.

(2) On an accrual basis and exclusive of acquisitions.

35

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

	Exploration and Production			Oilfield Services (1)			Total
Nine Months Ended September 30, 2014
Revenues	$	51,130		$	59,539		$	110,669
Direct operating expenses	16,252			34,849			51,101
Segment margin	$	34,878		$	24,690		$	59,568
General and administrative expenses	13,220			9,615			22,835
Depreciation, depletion, amortization and accretion	19,692			17,856			37,548
Income (loss) from operations	$	1,966		$	(2,781	)	$	(815	)
Capital expenditures (2)	$	19,284		$	6,726		$	26,010
At September 30, 2014
Total assets	$	194,541		$	239,983		$	434,524
Nine Months Ended September 30, 2013
Revenues	$	32,440		$	—		$	32,440
Direct operating expenses	10,698			—			10,698
Segment margin	$	21,742		$	—		$	21,742
General and administrative expenses (3)	11,452			—			11,452
Depreciation, depletion, amortization and accretion	11,831			—			11,831
Loss from operations	$	(1,541	)	$	—		$	(1,541	)
Capital expenditures (2)	$	18,261		$	—		$	18,261
At December 31, 2013
Total assets	$	181,440		$	73,270		$	254,710

__________

(1) The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion.

(2) On an accrual basis and exclusive of acquisitions.

(3) Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

16.  Subsequent Events

Equity Offering. On October 3, 2014, the Partnership and our general partner entered into an Equity Distribution Agreement (the “Agreement”) with BMO Capital Markets Corp. (the “Sales Agent”). Pursuant to the terms of the Agreement, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. Sales of such common units, if any, will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange at market prices, or as otherwise agreed by the Partnership and the Sales Agent. On October 6, 2014, the Partnership sold 720,000 common units under the Agreement for net proceeds of approximately $16.4 million. Proceeds will be used to pay down a portion of the Partnership's credit facility and for general corporate purposes.

36

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

Distributions.On October 21, 2014, the Partnership declared quarterly distributions of $0.585 per unit to unitholders of record, including holders of common, subordinated and general partner units for the three months ended September 30, 2014. The following distributions will be paid on November 14, 2014 to holders of record as of the close of business on November 3, 2014 (in thousands):

	Common Units		Subordinated Units		General Partner Units		Total
Distributions	$	9,454	$	1,290	$	91	$	10,835

Lease. On October 27, 2014, MCE entered into a master lease agreement whereby it can enter into capital leases for certain property and equipment totaling up to $25 million. The master lease agreement does not obligate MCE to enter into any such leases, and no amounts are currently outstanding under this master lease agreement.

37

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(Unaudited)

ITEM 2.         Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis is intended to help investors understand the Partnership’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Partnership’s accompanying unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as the Partnership’s audited consolidated financial statements and the accompanying notes included in the 2013 Form 10-K. The Partnership’s discussion and analysis includes the following subjects:

•Overview;

•Results by Segment;

•Results of Operations;

•Liquidity and Capital Resources; and

•Critical Accounting Policies and Estimates.

The financial information with respect to the three and nine months ended September 30, 2014 and 2013, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements in accordance with GAAP. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control, including among other things, the risk factors discussed in "Item 1A. Risk Factors" of this Quarterly Report. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statements Regarding Forward-Looking Statements" in this Quarterly Report.

Overview

We are a vertically integrated independent energy partnership formed in October 2012. The Partnership is engaged in the development and 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, the Partnership is engaged in oilfield services through its oilfield services subsidiaries. Our oilfield services business provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, throughout the Mid-Continent region and in South Texas and West Texas. In June 2014, we acquired oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry primarily in Oklahoma, Texas, Pennsylvania and Ohio.

Our business operates in two segments: (i) exploration and production and (ii) oilfield services. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions.

Recent Developments

Services Acquisition.On June 26, 2014, the Partnership acquired 100% of the outstanding membership interests in EFS and RPS for total consideration of approximately $113.2 million. The Services Acquisition helps to facilitate the Partnership's goals of becoming a more fully integrated oil and natural gas partnership.

38

Results by Segment

The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, 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 relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) revenues, (ii) operating expenses, (iii) segment margin, (iv) adjusted EBITDA and (v) distributable cash flow.

To evaluate the performance of the Partnership’s business segments, management uses the excess of revenue over direct operating expenses or segment margin. Results of these measurements provide important information to management about the activity, profitability and contributions of the Partnership's business segments. The results of the Partnership's business segments for the three and nine months ended September 30, 2014 and 2013 are discussed below.

Exploration and Production Segment

The Partnership generates a portion of its consolidated revenues and cash flow from the production and sale of oil, natural gas and NGLs. The exploration and production segment’s revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs and on the Partnership's reserves. The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our oil, natural gas and NGL production, the quantity of oil, natural gas and NGLs we produce, the costs incurred on our production and changes in the fair value of our commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. The exploration and production segment's 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.

In order to reduce the Partnership’s exposure to price fluctuations, we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

Set forth in the table below is financial, production and pricing information for our exploration and production segment for the three and nine months ended September 30, 2014 and 2013. For periods prior to the completion of our initial public offering in February 2013, the data below reflects results attributable to the IPO Properties. For periods following the completion of our initial public offering, the data below reflects results attributable to the IPO Properties for the entire period, and properties subsequently acquired from the closing date of their respective acquisition forward.

39

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014		2013
Results (in thousands):
Oil sales	$	3,798		$	2,044	$	12,146	$	4,879
Natural gas sales	3,711			2,582		12,928		7,031
NGL sales	8,052			7,805		26,056		20,530
Total revenues	15,561			12,431		51,130		32,440
Production expenses	4,894			3,428		13,913		8,702
Production taxes	668			557		2,339		1,996
Total segment margin	9,999			8,446		34,878		21,742
General and administrative	7,354			1,353		13,220		11,452
Depreciation, depletion, amortization and accretion	6,834			4,972		19,692		11,831
Operating (loss) income	$	(4,189	)	$	2,121	$	1,966	$	(1,541	)
Production volumes:
Oil (Bbls)	39,990			19,900		124,296		51,124
Natural gas (Mcf)	960,434			755,889		2,876,478		1,955,786
NGLs (Bbls)	227,439			216,225		674,717		588,431
Total production volumes (Boe)(1)	427,501			362,107		1,278,426		965,519
Average daily production volumes (Boe)	4,647			3,936		4,683		3,537
Average price (excluding derivatives):
Oil (per Bbl)	$	94.97		$	102.71	$	97.72	$	95.43
Natural gas (per Mcf)	$	3.86		$	3.42	$	4.49	$	3.59
NGL (per Bbl)	$	35.40		$	36.10	$	38.62	$	34.89
Total (per Boe)	$	36.40		$	34.33	$	39.99	$	33.60
Average production costs (per Boe)(2)	$	11.45		$	9.47	$	10.88	$	9.01

__________

(1) Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of oil.

(2) Includes lease operating expense and workover expense.

Revenue

Revenues from our exploration and production segment were $15.6 million for the three months ended September 30, 2014, an increase of $3.1 million, or 25.2%, compared to the three months ended September 30, 2013. Revenues were $51.1 million for the nine months ended September 30, 2014, an increase of $18.7 million, or 57.6%, compared to the nine months ended September 30, 2013. The increase in revenues during the three and nine months ended September 30, 2014 was primarily due to increased production from oil and natural gas properties acquired during 2013 and 2014. Production increased 65,394 Boe, or 18.1%, and 312,907 Boe, or 32.4%, in the three and nine months ended September 30, 2014, respectively, from the same periods in 2013. Additionally, the increase in prices received on our production contributed to higher revenues in the three and nine months ended September 30, 2014 compared to the same periods in 2013. The average price per Boe received on our combined production increased $2.07, or 6.0%, and $6.39, or 19.0%, in the three and nine months ended September 30, 2014, respectively, from the same periods in 2013.

Operating Expenses

Production expenses. Production expense includes costs associated with exploration and production activities, including lease operating expense and treating costs. Production expenses increased $1.5 million, or 42.8%, for the three months ended September 30, 2014 from the three months ended September 30, 2013 and $5.2 million, or 59.9%, for the nine months ended September 30, 2014 from the nine months ended September 30, 2013. The increase in production expenses for the three and nine

40

months ended September 30, 2014 was partially due to increased production from oil and natural gas properties acquired during 2013 and 2014, a portion of which relates to acquisitions in the Southern Dome field, which produces more oil than properties in our other fields. Higher production costs were incurred on oil production compared to production costs on natural gas volumes. In addition, we incurred higher operator fees and costs on our production in 2014. As a result of these factors, production expense increased $1.98 per Boe and $1.87 per Boe for the three and nine months ended September 30, 2014, respectively, compared to the same periods in 2013. As a non-operating working interest owner, we are subject to costs and fees as incurred and determined by the operator. We monitor such costs and are working with our contract operator and other working interest owners to ensure costs are reasonable.

Production taxes. Production taxes increased $0.1 million, or 19.9%, and $0.3 million, or 17.2%, in the three and nine months ended September 30, 2014, respectively, from the same periods in 2013. The increase in production taxes is due to the increase in volumes produced and prices received on our production in 2014 versus 2013. A portion of our wells benefit from certain tax credits relating to the drilling of horizontal wells. Due to these credits and the types of wells drilled, our production taxes will fluctuate from period to period in addition to variances from changes in production.

General and administrative. General and administrative expense increased $6.0 million, or 443.5%, for the three months ended September 30, 2014 from the same period in 2013. The increase in 2014 is primarily due to an $5.4 million change in the fair value of the contingent consideration on certain acquisitions made in 2013 and 2014. Also contributing to the increase in 2014 is additional corporate costs related to salary and benefits due to an increase in the number of corporate-level employees. Partially offsetting the increase is a decrease of $0.7 million in fees paid in 2013 to NSEC for administrative services as there were no such fees paid in 2014.

General and administrative expense increased $1.8 million, or 15.4%, for the nine months ended September 30, 2014 from the same period in 2013. The increase is primarily due to $4.5 million related to the change in fair value of the contingent consideration on certain acquisitions made during 2013 and 2014 and $3.3 million for acquisition related costs. Also contributing to the increase is additional corporate costs related to salary and benefits due to an increase in the number of corporate-level employees in 2014. Offsetting the increase is a decrease in equity-based compensation of $7.1 million and approximately $2.0 million of fees paid to NSEC for administrative services in 2013.

Depreciation, depletion, amortization and accretion. Depreciation, depletion, amortization and accretion expense increased $1.9 million and $7.9 million for the three and nine months ended September 30, 2014, respectively, from the comparable periods in 2013. The majority of the increase in depreciation, depletion and amortization is attributable to the increase in combined production during 2014.

Oilfield Services Segment

The financial results of our oilfield services segment depend primarily on demand and prices that can be charged for its services. The primary factors affecting the results of the oilfield services segment are the rates received and the amount of oilfield services provided. The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. As such, comparative information for the 2013 period is not available. In June 2014, we acquired oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry primarily in Oklahoma, Texas, Pennsylvania and Ohio. See Note 2 "Acquisitions" for discussion of these acquisitions.

	Three Months Ended September 30, 2014			Nine Months Ended September 30, 2014
Results (in thousands):
Oilfield service revenue	$	40,863		$	59,539
Cost of providing oilfield services	24,315			34,849
Total segment margin	16,548			24,690
General and administrative	6,431			9,615
Depreciation, depletion and amortization	11,003			17,856
Operating loss	$	(886	)	$	(2,781	)

41

Revenue

Revenues from our oilfield services segment was $40.9 million and $59.5 million for the three and nine months ended September 30, 2014, respectively. Oilfield services revenues fluctuate based on drilling activity in the areas in which we operate.

Operating Expenses

Costs of providing oilfield services. The cost of providing oilfield services was $24.3 million and $34.8 million for the three and nine months ended September 30, 2014, respectively.

General and administrative. General and administrative expense of $6.4 million and $9.6 million for the three and nine months ended September 30, 2014, respectively, represents the costs for ongoing operations in our expanding oilfield services segment.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense of $11.0 million and $17.9 million for the three and nine months ended September 30, 2014, respectively, primarily represents the amortization of our intangible assets from the MCE Acquisition, the MCCS Acquisition and the Services Acquisition.

See “Results of Operations” below for a discussion of other income (expense).

Results of Operations

Refer to "Results by Segment" for discussion of our operating revenues and expenses.

	Three Months Ended   September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	(in thousands)
Operating (loss) income	$	(5,075	)	$	2,121		$	(815	)	$	(1,541	)
Other income (expense):
Interest expense	(1,458		)	(654		)	(3,442		)	(3,220		)
Gain (loss) on derivative contracts, net	3,768			(3,453		)	(760		)	(2,597		)
Gain on investment in acquired business	—			—			2,298			—
Other income	11			—			18			—
Loss before income taxes	(2,754		)	(1,986		)	(2,701		)	(7,358		)
Income tax benefit	—			—			—			12,126
Net (loss) income	$	(2,754	)	$	(1,986	)	$	(2,701	)	$	4,768

Other Income/Expense

Interest expense. Interest expense increased $0.8 million, or 122.9%, for the three months ended September 30, 2014 from the three months ended September 30, 2013. The increase was due to higher average debt balances in 2014 compared to 2013, primarily as a result of additional borrowings under our credit facility as a result of acquisitions and corporate growth. Interest expense increased $0.2 million or 6.9% for the nine months ended September 30, 2014 from the nine months ended September 30, 2013. The increase was due to higher average debt balances in 2014 compared to 2013, primarily as a result of additional borrowings under our credit facility as a result of acquisitions and corporate growth. This increase was partially offset by a write off of $1.4 million of loan fees associated with extinguishing debt in 2013.

42

Gain (loss) on derivatives, net. The following table presents gain (loss) on our derivative contracts for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Total gain (loss) on derivative contracts, net (1)	$	3,768	$	(3,453	)	$	(760	)	$	(2,597	)

__________

(1) Included in the gain (loss) on derivative contracts for the three months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $0.3 million and $0.5 million, respectively. Included in the loss on derivative contracts for the nine months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $3.8 million and $0.9 million, respectively.

Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded each quarter as a component of operating expenses. In general, cash is received on settlement of contracts due to lower oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps, and cash is paid on settlement of contracts due to higher oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps.

Gain on investment in acquired business. As discussed in Note 2 "Acquisitions," 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 for the nine months ended September 30, 2014.

Income taxes.Income tax benefit was $12.1 million for the nine months ended September 30, 2013. The IPO Properties were owned by a tax paying entity in 2012 and incurred deferred income taxes based on the differences in book and tax basis of the properties at that date. Upon completion of our initial public offering, all of our properties were owned by a nontaxable entity, and at such time we recognized a tax benefit due to the change in tax status.

Non-GAAP Financial Measures

Adjusted EBITDA. We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, non-cash compensation expense, non-recurring advisory fees and acquisition costs, unrealized derivative gains and losses and non-recurring gains and losses.

Our management believes Adjusted EBITDA, a non-GAAP financial measure, is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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A reconciliation of Adjusted EBITDA to net (loss) income for the three and nine months ended September 30, 2014 and 2013 is provided below:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013 (1)			2014			2013 (1)
Reconciliation of adjusted EBITDA to net (loss) income:	(in thousands)
Net (loss) income attributable to New Source Energy Partners L.P.	$	(2,996	)	$	(1,986	)	$	(2,943	)	$	4,768
Interest expense	1,458			654			3,442			3,220
Franchise tax expense (income tax benefit)	41			—			41			(12,126		)
Depreciation, depletion and amortization	17,760			4,913			37,329			11,686
Accretion expense	77			59			219			145
Non-cash compensation expense	1,262			—			1,906			7,738
Acquisition and transaction fees	392			556			3,624			461
Gain on acquisition of business	—			—			(2,298		)	—
(Gain) loss on derivative contracts, net	(3,768		)	3,453			760			2,597
Cash paid on settlement of derivative contracts	(338		)	(537		)	(3,750		)	(878		)
Change in fair value of contingent consideration	5,404			—			4,493			—
Adjusted EBITDA	$	19,292		$	7,112		$	42,823		$	17,611

__________

(1) Reflects certain changes to align to current methodology for preparing Adjusted EBITDA.

A reconciliation of Adjusted EBITDA to net loss for our exploration and production and oilfield services segments for the three and nine months ended September 30, 2014 is provided below:

	Three Months Ended						Nine Months Ended
	September 30, 2014						September 30, 2014
	E&P			OFS			E&P			OFS
Reconciliation of adjusted EBITDA to net loss:	(in thousands)
Net loss attributable to New Source Energy Partners L.P.	$	(1,598	)	$	(1,398	)	$	581		$	(3,524	)
Interest expense	936			522			2,681			761
Franchise tax expense	—			41			—			41
Depreciation, depletion and amortization	6,757			11,003			19,473			17,856
Accretion expense	77			—			219			—
Non-cash compensation expense	—			1,262			644			1,262
Acquisition and transaction fees	300			92			3,315			309
Gain on acquisition of business	—			—			(2,298		)	—
(Gain) loss on derivative contracts, net	(3,768		)	—			760			—
Cash paid on settlement of derivative contracts	(338		)	—			(3,750		)	—
Change in fair value of contingent consideration	5,404			—			4,493			—
Adjusted EBITDA	$	7,770		$	11,522		$	26,118		$	16,705

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility and other debt instruments and the issuance of equity securities in the capital markets. To date, our primary uses of capital has been for the acquisition and development of oil and natural gas properties, the acquisition of our oilfield services

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business through the MCE Acquisition and the Services Acquisition, distributions to our unitholders and working capital needs. For the remainder of 2014 and 2015, we believe that cash on hand, net cash flows generated from operations and proceeds from borrowings under debt instruments or equity offerings will be adequate to fund our capital budget, pay distributions to our unitholders and satisfy our short–term liquidity needs. We may also utilize borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long–term liquidity needs. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions, the outcome of the redetermination of our borrowing base, which is currently in process, and our financial condition. Additionally, the issuance of common units, whether for equity offerings or to settle our contingent consideration obligations, will result in a higher number of units for which we will pay distributions.

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, and to pay distributions to our unitholders will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, particularly for oil, natural gas and NGLs, and our ongoing efforts to manage production volumes, operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Capital Requirements

Because we distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production, and as a result, we may not grow as quickly as other oil and natural gas entities or at all. We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including borrowings under our credit facility and other debt instruments and the issuance of equity securities, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. Because our proved reserves and production decline continually over time and because we own a limited amount of undeveloped properties, we may need to make acquisitions to sustain our level of distributions to unitholders over time. 

Distributions

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. To facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions for certain purposes, including in circumstances where our general partner believes that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions.

Distributions are declared and distributed within 45 days following the end of each quarter. The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common, subordinated and general partner units during the three and nine months ended September 30, 2014 and 2013, as shown in the following table (in thousands):

Distributions	Common Units		Subordinated Units		General Partner Units		Total
2014
First Quarter (1)	$	4,681	$	1,268	$	89	$	6,038
Second Quarter (2)	$	7,852	$	1,279	$	90	$	9,221
Third Quarter (3)	$	9,025	$	1,290	$	91	$	10,406
2013
Second Quarter (4)	$	1,857	$	604	$	43	$	2,504
Third Quarter (1)	$	3,895	$	1,268	$	89	$	5,252

__________

(1)    Reflects quarterly distributions of $0.575 per unit paid in the third quarter of 2013 and the first quarter of 2014.

(2)    Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014.

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(3)    Reflects quarterly distributions of 0.585 per unit paid in the third quarter of 2014.

(4)    Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.

On October 21, 2014, the Partnership declared quarterly distributions of $0.585 per unit to unitholders of record, including holders of common, subordinated and general partner units for the three months ended September 30, 2014. The following distributions will be paid on November 14, 2014 to holders of record as of the close of business on November 3, 2014 (in thousands):

	Common Units		Subordinated Units		General Partner Units		Total
Distributions	$	9,454	$	1,290	$	91	$	10,835

Cash Flows

Net cash provided by operating activities was approximately $26.4 million and $9.7 million for the nine months ended September 30, 2014 and 2013, respectively. The increase in the cash provided by operating activities is a result of the acquisitions that occurred throughout 2013 and in 2014, which increased the Partnership's overall oil and natural gas production and revenue from oilfield services.

Net cash used in investing activities was approximately $91.0 million and $34.2 million for the nine months ended September 30, 2014 and 2013, respectively. The increase is primarily attributable to the Services Acquisition and the CEU Acquisition during 2014.

Net cash provided by financing activities was approximately $63.0 million and $24.8 million for the nine months ended September 30, 2014 and 2013, respectively. Financing cash flows are primarily related to debt and equity financing of the property development and working capital. The increase in net cash provided by financing activities is primarily due to the equity offering in April 2014.

Working Capital

Working capital is the difference in current assets and current liabilities and is an indicator of liquidity and the potential need for short-term funding. The change in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, and maintenance capital expenditures. Our working (deficit) capital was $(37.8) million and $3.7 million at September 30, 2014 and December 31, 2013, respectively. The working deficit is primarily attributable to the contingent consideration from the MCE Acquisition, MCCS Acquisition and Services Acquisition and the factoring payable and notes payable assumed in the Services Acquisition. The MCE Contingent Consideration and the MCCS Contingent Consideration will be paid with common units and the EFS/RPS Contingent Consideration will be paid with a combination of cash and common units. Based on fair value of the EFS/RPS Contingent Consideration of approximately $21.0 million at September 30, 2014, approximately $10.5 million would be paid in cash with the remainder paid in common units. However, the former owners can elect to receive a larger portion of the payout in common units.

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage) and is estimated as the amount of capital expenditures necessary to maintain the revenue generating capabilities of our assets at current levels over the long term. With respect to our oil and natural gas operations, estimated maintenance capital expenditures represents the average cost to replace a barrel of oil equivalent, using the historical average finding and development costs over the preceding five-year period and the actual production volume for such period. However, future finding and development costs could be higher, which could result in drilling opportunities being limited or uneconomic. With respect to our oilfield services operations, estimated maintenance capital expenditures represent the estimated replacement costs for current equipment whose useful lives are scheduled to be completed during the given year. For the nine months ended September 30, 2014, our maintenance capital expenditures were approximately $12.8 million.

Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The purpose of growth capital is primarily to acquire producing assets that will increase our distributions per unit and secondarily to increase the rate of development and production of our existing properties and increase the size and scope of our oilfield services business in a manner that is expected to be accretive to our unitholders. Growth capital expenditures on existing

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properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. We expect to primarily rely upon external financing sources, including borrowings under our credit facility and the issuance of equity securities, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions. We are party to other operating agreements pursuant to which the operator could decide to engage in capital spending that would require us to pay our share or suffer substantial penalties.

As our future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production, there can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures. Additionally, it is likely that we will incur higher finding and development costs on future drilling opportunities, which would likely result in such drilling activities being curtailed or delayed. If we do not pursue drilling activities, our reserve and production will decrease over time and not be replaced. We may increase or decrease planned capital expenditures, including acquisitions, depending on oil, natural gas and NGL prices, the availability of capital through the issuance of additional common units or long-term debt. A decrease in capital expenditures could limit our ability to increase or replace our reserves, which could reduce our production volumes over time.

Credit Facility

Our credit facility is a four-year, senior secured credit facility. The amount we may borrow under the credit facility is limited to a borrowing base, which is primarily based on the value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders at their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated oil, natural gas, and NGL reserves, which will take into account the prevailing oil, natural gas, and NGL prices at such time, as adjusted for the impact of our derivative contracts.

Declines in commodity prices, increases in production costs and other factors that impact our reserves could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we will be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our credit facility. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our credit facility.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At September 30, 2014 and December 31, 2013, the average annual interest rate on borrowings outstanding under the credit facility was 3.25%. At September 30, 2014, the borrowing base under the credit facility was $102.5 million with $10.25 million of available borrowing capacity and no available borrowing capacity before restriction on distribution occurs. In October 2014, the Partnership repaid $9.25 million in borrowings under the credit facility, which increases the amount of available borrowing capacity before restriction on distribution occurs by $9.25 million.

As of September 30, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. As of September 30, 2014, the Partnership was in compliance with all covenants under the credit facility.

The semi-annual redetermination of the borrowing base on our credit facility is currently in process. The borrowing base is subject to a number of factors including quantities of proved oil, natural gas and NGL reserves and the bank's price assumptions. Based on our reserve estimates and applicable commodity pricing, we may have a decrease to our borrowing base as a result of the current redetermination. Additionally, a reduction in the borrowing base could result in amounts being due in the near term or limit the availability of borrowings available in the future under the credit facility. As of November 13, 2014, the redetermination of our borrowing base had not been finalized.

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Line of Credit

In February 2014, MCE entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. Interest only payments are due monthly with the line of credit maturing in February 2015. The line of credit replaced MCES' factoring payable agreement described below. Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at September 30, 2014. The line of credit is secured by accounts receivable, inventory, chattel paper and general intangibles of MCES. Based on the outstanding balance of $3.3 million, there was $0.7 million of available borrowing capacity at September 30, 2014.

As of September 30, 2014, the line of credit contained a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of September 30, 2014, MCE was in compliance with this covenant under the line of credit.

Notes Payable

The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. These notes range from 12-60 months in duration with maturity dates from August 2015 through April 2018 and carry variable interest rates ranging from 5.28% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. In August 2014, MCES entered into $3.5 million of additional notes payable. At September 30, 2014, the Partnership had $7.7 million outstanding under the MCES notes payable as of September 30, 2014.

In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on term loans held by EFS. These term loans had a balance of $14.2 million as of September 30, 2014 and mature on June 26, 2015. The term loans have a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at September 30, 2014, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The term loans are collateralized by various assets of the parties to the agreement and guaranteed by MCE and former owners of EFS and RPS. The Partnership is required to maintain a reserve bank account into which the lesser of $0.3 million or 100% of excess cash flow (as defined in the loan agreement) shall be deposited quarterly and used to fund an additional annual payment on September 30th of each year during the term of the loans.

The EFS term loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, beginning October 1, 2014, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0 (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $4.0 million, in each case as more fully described in the loan agreement.

Factoring Payable

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 $15.5 million as of September 30, 2014.

Equity Offering

On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million. We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes.

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On October 3, 2014, the Partnership and our general partner entered into the Agreement with the Sales Agent. Pursuant to the terms of the Agreement, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. Sales of such common units, if any, will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange at market prices, or as otherwise agreed by the Partnership and the Sales Agent. On October 6, 2014, the Partnership sold 720,000 common units under the Agreement for net proceeds of approximately $16.4 million. Proceeds were be used to pay down a portion of the Partnership's credit facility and will be used for general corporate purposes.

Outlook

As our revenue, earnings and cash flow are, in part, dependent on oil, natural gas and NGL prices, lower prevailing and future prices could result in lower revenue, earnings and cash flow. Prevailing and future prices for oil, natural gas and NGLs depend on numerous factors beyond our control such as economic conditions, regulatory developments and competition from other energy sources. The energy markets historically have been volatile and recent oil prices have declined from those earlier in 2014 and may fluctuate significantly in the future. Lower prices may reduce the amount of oil, natural gas or NGLs that we can produce economically. A decline in prices could have a material adverse effect on the estimated value and estimated quantities of our reserves, our ability to fund our operations and to pay distributions to our unitholders, as well as to our financial condition, cash flows, results of operations and access to capital. Our derivative arrangements serve to mitigate a portion of the effect of this price volatility on our cash flows. We will need to incur capital expenditures in the remainder of 2014 and 2015 to develop our reserves; however, such capital expenditures are dependent on availability under the credit facility and other debt instruments, proceeds from equity issuances, along with cash flows from operating activities.

For purposes of determining the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves and calculating its full cost ceiling limitation, we use 12-month average oil and natural gas prices for the most recent 12 months as of the balance sheet date and adjusted for basis or location differential, held constant over the life of the reserves. The average oil price, WTI Cushing, used in such calculations within the 12-month period ended September 30, 2014 was $99.08 Bbl and the average natural gas price, at Henry Hub, was $4.24 Mcf. The first-day-of-the-month oil prices for October and November 2014 were $90.73 Bbl and $80.54 Bbl, respectively, resulting in an average oil price for the 12-month period ended November 30, 2014 of $96.96 per barrel, a decrease of approximately 2% as compared to the 12-month period ended September 30, 2014 average price. The first-day-of-the-month natural gas prices for October and November 2014 were $4.14 Mcf and $3.80 Mcf, respectively, resulting in an average natural gas price for the 12-month period ended November 30, 2014 of $4.31 Mcf, an increase of approximately 2%. If the current downward trend in oil prices continues, there is a reasonable likelihood that the Partnership could incur an impairment to our full cost pool in 2015. Additionally, as a non-operator of our properties, we cannot control the costs our operator may incur and pass along to us. Higher production costs could result in a reduction to how much we are able to economically produce and to our reserves becoming uneconomic, which could result in an impairment of our full cost pool.

Based on our current oil, natural gas and NGL price expectations, we anticipate that our cash flow from operations, borrowings under our credit facility and other debt instruments and the issuance of common units will address our planned capital expenditures and other cash requirements for the remainder of 2014 and 2015. However, future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production. Additionally, our ability to access the capital markets or obtain financing at competitive rates is dependent upon various factors including prevailing market conditions and our financial condition.

Contractual Obligations

From time to time, we enter into transactions that can give rise to significant contractual obligations. Since December 31, 2013, we have completed the CEU Acquisition, the MCCS Acquisition and the Services Acquisition. These acquisitions or transactions conducted in conjunction with these acquisitions resulted in the following contractual obligations as of September 30, 2014, which are in addition to the contractual obligations of the Partnership that were presented in the 2013 Form 10-K.

• Notes payable. The principal amount of $16.8 million assumed in the Services Acquisition is due in June 2015. Additionally, MCE entered into notes payable totaling $6.7 million with maturity ranging from 10-48 months.

• Leases. EFS and RPS have leases, primarily for field offices, in place through September 2022. Amounts due under such leases are approximately $0.1 million for remainder of 2014, $0.4 million for 2015, $0.3 million for each of 2016 through 2018, and $0.8 million thereafter.

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Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves, the fair value of assets and liabilities acquired in business combinations, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. Actual results could differ from these estimates.

Refer to Note 1 of the consolidated financial statements and Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations" included in the 2013 Form 10-K for a description of the Partnership's critical accounting policies and estimates.

ITEM 3.         Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including volatility in commodity prices and interest rates.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, natural gas and NGL production. Due to the volatility of commodity prices, we periodically enter into derivative contracts to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations for a portion of our oil, natural gas and NGL production. While the use of derivative contracts limits our 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. Our derivative contracts apply to only a portion of our expected production, provide only partial price protection against declines in market prices and limit our potential gains from future increases in market prices. We do not enter into derivative contracts for speculative or trading purposes.

Our hedging strategy includes entering into commodity derivative contracts covering approximately 50% to 90% of our estimated total production over a three-to-five year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a derivative contract is terminated prior to its expiration.

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At September 30, 2014, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.
Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.
Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the put option and the fixed price.
Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The following tables present our derivative instruments outstanding as of September 30, 2014:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2014	23,763	$	80.00	$	103.50
2015	42,649	$	80.00	$	93.25

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	36,500	$	77.50	$	92.50	$	102.60

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2014	260,751	$	4.00	$	4.41
2015	1,362,382	$	4.00	$	4.32

Oil put options	Volumes (Bbls)	Floor Price
2014	7,418	$	80.00

Natural gas put options	Volumes (MMBtu)	Floor Price
2014	99,034	$	3.50
2015	798,853	$	3.50
2016	930,468	$	3.50

NGL put options	Volumes (Bbls)	Average Floor Price
2014	5,535	$	63.19

51

Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	6,900	$	103.52
2015	39,411	$	88.90
2016	36,658	$	86.00

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2014	176,795	$	4.09
2015	800,573	$	4.25
2016	629,301	$	4.37

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	168,924	$	39.44
2015	84,793	$	75.18

Our derivative contracts are based on WTI futures prices for oil, Henry Hub future prices for natural gas and Conway and Mont Belvieu future prices for NGLs. We are generally required to settle our commodity derivatives within five days of the end of the month.

As the Partnership has not designated any of its derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts are recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price.

The following table presents gain (loss) on our derivative contracts as included in the accompanying unaudited statements of operations for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Total gain (loss) on derivative contracts, net (1)	$	3,768	$	(3,453	)	$	(760	)	$	(2,597	)

__________

(1) Included in the gain (loss) on derivative contracts for the three months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $0.3 million and $0.5 million, respectively. Included in the loss on derivative contracts for the nine months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $3.8 million and $0.9 million, respectively.

See Note 6 "Derivative Contracts" to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding our commodity derivatives.

Credit Risk

All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an "investment grade" credit rating. We monitor on an ongoing basis the credit ratings of our derivative counterparties and considers our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. Our derivative contracts are with multiple counterparties to minimize the exposure to any individual counterparty. A default by the Partnership under its credit facility constitutes a default under its derivative contracts with counterparties that are lenders under the credit facility. We do not require collateral or other security from counterparties to

52

support derivative instruments. We have master netting agreements with all of our derivative contract counterparties, which allows us to net our derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Partnership’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts. The Partnership’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against amounts owed, if any, to such counterparty under the credit facility. As of September 30, 2014, the majority of our open derivative contracts are with counterparties that share in the collateral supporting the credit facility. As a result, we are not required to post additional collateral under its derivative contracts.

Interest Rate Risk

At September 30, 2014, the Partnership had debt outstanding under its credit facility of $92.3 million. A 1% increase in LIBOR on the Partnership outstanding debt under its credit facility as of September 30, 2014 would result in an estimated $0.9 million increase in annual interest expense.

ITEM 4.       CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our audit committee, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2014. The term "disclosure controls and procedures," as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of September 30, 2014 at the reasonable assurance level due to the material weaknesses in internal control over financial reporting we identified in connection with preparing the 2013 Form 10-K and this Quarterly Report. The material weaknesses we identified, as disclosed in the 2013 Form 10-K and herein, relate to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review, an inaccurate revenue cutoff on an acquired business and insufficient resources, and the lack of a sufficient number of qualified personnel to timely and appropriately account for and disclose the impact of complex, non-routine transactions in accordance with GAAP. These non-routine transactions impacted the recording of equity-based compensation, cash flow presentations, revenue, business combination adjustments and disclosures and calculation of earnings (loss) per unit. The material weaknesses resulted in the recording of adjustments identified by our independent registered public accounting firm to our financial statements for the periods ended December 31, 2013 and June 30, 2014. Notwithstanding the existence of the material weaknesses, management has concluded that the financial statements included in this report present fairly, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with GAAP.

Management's Remediation Activities

With the oversight of senior management and our audit committee, we are taking steps intended to address the underlying causes of the material weaknesses, primarily through the hiring of more employees and engaging outside consulting firms with technical accounting and financial reporting experience and the implementation and validation of improved accounting and financial reporting procedures.

As of September 30, 2014, we have not yet been able to remediate these material weaknesses. However, we have hired additional personnel with experience in technical accounting research and financial reporting. Additionally, we are in the process of making enhancements to our accounting and reporting processes. We do not know the specific timeframe needed to remediate all of the control deficiencies underlying these material weaknesses. In addition, we may need to incur incremental costs associated with this remediation, primarily due to employee recruitment and retention and engagement with third-party consulting firms, and the implementation and validation of improved accounting and financial reporting procedures. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address the material weaknesses.

53

Changes in Internal Control over Financial Reporting

In 2014, we completed the acquisition of EFS and RPS. The acquisition of EFS and RPS added locations responsible for accounting and reporting functions. As a result, we are modifying our internal control processes and procedures to incorporate these entities. There were no additional material changes in our internal control over financial reporting during our most recent fiscal quarter.

Inherent Limitations on Effectiveness of Controls

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, even if determined effective and no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives to prevent or detect misstatements. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PART II – Other Information

ITEM 1.         Legal Proceedings

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and natural gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.

Refer to Note 14 "Commitments and Contingencies" of the condensed consolidated financial statements of this Quarterly Report for a discussion of legal proceedings.

We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.

54

ITEM 1A.     Risk Factors

The risk factor below updates the Partnership's risk factors discussed in Item 1A - Risk Factors in the Partnership's 2013 Form 10-K.

Recent listing of the lesser prairie chicken as a threatened species under the federal Endangered Species Act may serve to increase costs of operations, which could result in less cash available for distribution to our unitholders, or restrict or delay drilling activities, which could reduce the amount of oilfield services we may provide.

The federal Endangered Species Act ("ESA") and analogous state laws regulate activities that could have an adverse effect on threatened and endangered species. Operations in areas where threatened or endangered species or their habitat are known to exist may result in increased costs to implement mitigation or protective measures and also may restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons. On March 27, 2014, the U.S. Fish and Wildlife Service ("FWS") announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas and Oklahoma, where operations in which we hold non-operating interests, as a threatened species under the ESA. Listing of the lesser prairie chicken as threatened imposes restrictions on disturbances to critical habitat by landowners and drilling companies that would harass, harm or otherwise result in a "taking" of this species. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies ("WAFWA"), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased operating costs from species protection measures, time delays or limitations on the drilling program’s activities, which costs, delays or limitations could have a material adverse effect on our financial condition and results of operations. 

ITEM 6.          Exhibits

See the Exhibit Index accompanying this Quarterly Report.

55

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on November 14, 2014.

New Source Energy Partners L.P.
By: New Source Energy GP, LLC, its general partner
/s/ Richard D. Finley
By:	Richard D. Finley
Title:	Chief Financial Officer and Treasurer

56

EXHIBIT INDEX

		Incorporation by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
3.1	Certificate of Limited Partnership of New Source Energy Partners L.P.	S-1	333-185754	3.1	1/11/2013
3.2	First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.	8-K	001-35809	3.1	2/15/2013
3.3	First Amendment to the First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.	8-K	001-35809	3.1	11/18/2013
3.4	Certificate of Formation of New Source Energy GP, LLC	S-1	333-185754	3.4	1/11/2013
3.5	Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC	8-K	001-35809	3.2	2/15/2013
3.6	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC	8-K	001-35809	3.1	3/20/2013
31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934					*
31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934					*
32.1	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002					*
101.INS(a)	XBRL Instance Document					*
101.SCH(a)	XBRL Schema Document					*
101.CAL(a)	XBRL Calculation Linkbase Document					*
101.DEF(a)	XBRL Definition Linkbase Document					*
101.LAB(a)	XBRL Labels Linkbase Document					*
101.PRE(a)	XBRL Presentation Linkbase Document					*

57

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Kristian B. Kos, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of New Source Energy Partners L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2014

	/s/ Kristian B. Kos
By:	Kristian B. Kos
Title:	Chief Executive Officer
	New Source Energy GP, LLC
	(as general partner of New Source Energy Partners L.P.)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Richard D. Finley, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of New Source Energy Partners L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 14, 2014

	/s/ Richard D. Finley
By:	Richard D. Finley
Title:	Chief Financial Officer
	New Source Energy GP, LLC
	(as general partner of New Source Energy Partners L.P.)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q of New Source Energy Partners L.P. (the “Partnership”), as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, Kristian B. Kos, Chief Executive Officer of New Source Energy GP, LLC, the general partner of New Source Energy Partners L.P. and Richard D. Finley, Chief Financial Officer of New Source Energy GP, LLC, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to their knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

 Date: November 14, 2014

	/s/ Kristian B. Kos
By:	Kristian B. Kos
Title:	Chief Executive Officer
	New Source Energy GP, LLC
	(as general partner of New Source Energy Partners L.P.)

Date: November 14, 2014

	/s/ Richard D. Finley
By:	Richard D. Finley
Title:	Chief Financial Officer
	New Source Energy GP, LLC
	(as general partner of New Source Energy Partners L.P.)

XML

Acquisitions - Purchase Price Allocation for May Acquisitions (Details) (May Acquired Properties, USD $) In Thousands, unless otherwise specified	May 31, 2013
May Acquired Properties
Business Acquisition [Line Items]
Proved oil and natural gas properties	$ 8,165
Asset retirement obligations	(19)
Other liabilities	(254)
Total net assets	$ 7,892

XML

Debt - Schedule of Debt (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Line of Credit Facility [Line Items]
Outstanding Credit	$ 92,250	$ 78,500
Notes payable	21,889	2,233
Total debt	117,433	80,733
Less: current maturities of long-term debt	21,132	719
Long-term debt	96,301	80,014
Revolving Credit Facility
Line of Credit Facility [Line Items]
Outstanding Credit	$ 3,294	$ 0

XML

Acquisitions - Summary of Assets Acquired and Liabilities Assumed in MCCS Acquisition (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Jun. 26, 2014 MCCS
Business Acquisition [Line Items]
Cash			$ 109
Accounts receivable			524
Inventory			2,035
Other current assets			14
Property and equipment			107
Intangible Asset			1,700	[1]
Goodwill	43,534	23,974	4,060	[2]
Other assets			28
Total assets acquired			8,577
Accounts payable and accrued liabilities			(1,431)
Long-term debt			(791)
Total liabilities assumed			(2,222)
Total net assets			$ 6,355

[1] Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years

[2] Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS's business. Goodwill has been allocated to the oilfield services segment.

XML

Fair Value Measurements - Fair Value of Allocated Derivative Assets and Liabilities (Details) (Fair Value, Inputs, Level 3, USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Beginning balance	$ 1,866		$ (2,517)		$ (112)
Loss on derivative contracts	(3,277)		(2,432)		(1,522)
Transfers out	0	[1]	2,843	[1]	0	[1]
Cash paid upon settlement	446		2,106		669
Ending balance	(965)		0		(965)
Unrealized losses included in earnings relating to derivatives held at period end	$ (2,677)		$ 0		$ (884)

[1] Fair values related to the Company’s natural gas collars, natural gas and NGL put options and NGL fixed price swaps were transferred from Level 3 to Level 2 in the second quarter of 2014 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the three and nine months ended September 30, 2013, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

XML

Debt (Details) (USD $)	9 Months Ended					9 Months Ended			9 Months Ended						9 Months Ended						1 Months Ended					9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 Notes Payable to Banks	Sep. 30, 2014 Term Loans	Sep. 30, 2014 Minimum	Sep. 30, 2014 Minimum Notes Payable to Banks	Sep. 30, 2014 Minimum Term Loans	Sep. 30, 2014 Maximum	Sep. 30, 2014 Maximum Notes Payable to Banks	Sep. 30, 2014 Federal Funds Rate	Sep. 30, 2014 Base Rate Term Loans	Sep. 30, 2014 Base Rate Minimum	Sep. 30, 2014 Base Rate Minimum Term Loans	Sep. 30, 2014 Base Rate Maximum	Sep. 30, 2014 London Interbank Offered Rate (LIBOR)	Sep. 30, 2014 London Interbank Offered Rate (LIBOR) Minimum	Sep. 30, 2014 London Interbank Offered Rate (LIBOR) Maximum	Sep. 30, 2014 Revolving Credit Facility	Dec. 31, 2013 Revolving Credit Facility	Oct. 31, 2014 Revolving Credit Facility Subsequent Event	Sep. 30, 2014 Revolving Credit Facility Bank of Oklahoma Corporation National Prime Rate	Aug. 31, 2014 MidCentral Energy Services Notes Payable to Banks	Sep. 30, 2014 MidCentral Energy Services Revolving Credit Facility	Feb. 28, 2014 MidCentral Energy Services Revolving Credit Facility	Sep. 30, 2014 EFS and RPS Minimum Term Loans	Sep. 30, 2014 EFS and RPS Maximum Term Loans
Debt Instrument [Line Items]
Required ratio of EBITDA to interest expense						2.5
Required ratio of total debt to EBITDA									3.5
Required current ratio						1.0
Maximum borrowing base utilization permitted under credit facility	90.00%
Basis spread on debt instruments											0.50%	(2.30%)	1.50%		2.25%	1.00%	2.50%	3.25%
Commitment fee percentage	0.50%
Interest rates on debt instruments	3.25%		3.25%									5.50%										4.00%
Line of credit current borrowing capacity																			$ 102,500,000						$ 4,000,000
Line of credit remaining borrowing capacity																			10,250,000		9,250,000			700,000
Available borrowing capacity before distribution restrictions																			0
Repayments on borrowings	8,401,000	95,000,000																			9,250,000
Long-term Debt				7,700,000																			3,500,000
Durations of debt instruments							12 months			60 months
Stated rates on debt instruments							5.28%			10.51%				5.50%
Term loans balance					14,200,000
Minimum balance required to be maintained on reserve bank account								300,000
Percentage of excess cash flow to be maintained as balance of reserve account if greater than $0.3 million					100.00%
Required fixed-charge ratio																										1.25
Required leverage ratio																											1.5
Required working capital and cash balance																										4,000,000.0
Line of credit maximum borrowing capacity																									4,000,000.0
Outstanding balance of line of credit	$ 92,250,000		$ 78,500,000																$ 3,294,000	$ 0					$ 3,300,000
Required debt service coverage ratio	1.25

XML

Earnings per Unit - Earnings Per Unit (Details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended	3 Months Ended			5 Months Ended	9 Months Ended
	Feb. 11, 2013	Sep. 30, 2014	Sep. 30, 2013		Jun. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Common units excluded from EPS calculation because of antidilutive effect		3,257				9,664
Net loss	$ 5,303	$ (2,996)	$ (1,986)		$ (535)	$ (2,943)	$ 4,768
Common Stock Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss		(2,599)	(1,473)	[1]		(2,503)	(76)	[1]
Weighted average units outstanding		15,428,822	6,773,500			12,646,084	6,480,439
Basic and diluted income per unit (in usd per unit)		$ (0.17)	$ (0.22)			$ (0.20)	$ (0.01)
Subordinated Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss		(371)	(479)	[1]		(411)	(430)	[1]
Weighted average units outstanding		2,205,000	2,205,000			2,205,000	2,205,000
Basic and diluted income per unit (in usd per unit)		$ (0.17)	$ (0.22)			$ (0.19)	$ (0.20)
General Partnership Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net loss		$ (26)	$ (34)	[1]		$ (29)	$ (29)	[1]
Weighted average units outstanding		155,102	155,102			155,102	154,503
Basic and diluted income per unit (in usd per unit)		$ (0.17)	$ (0.22)			$ (0.19)	$ (0.19)

[1] Reflects net loss from February 13, 2013 through September 30, 2013 for the nine months ended September 30, 2013.

XML

Acquisitions - Purchase Price Allocation of CEU Acquisition (Details) (USD $)				0 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Jan. 31, 2014 CEU Paradigm		Sep. 30, 2014 CEU Paradigm
Business Acquisition [Line Items]
Cash				$ 5,503,000
Fair value of common units granted				11,621,000	[1]
Contingent consideration	36,854,000	26,609,000	6,320,000	0	[2]	0
Total fair value of consideration				17,124,000
Property and equipment				17,306,000
Asset retirement obligations				(182,000)
Total net assets				$ 17,124,000

[1] The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition).

[2] The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period (the "CEU Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):

	September 30, 2014			December 31, 2013
Vehicles and transportation equipment	$	15,317		$	561
Machinery and equipment	38,746			4,757
Office furniture and equipment	472			79
Iron	11,212			2,971
Total	65,747			8,368
Less: accumulated depreciation	(2,466		)	(202		)
Property and equipment, net	$	63,281		$	8,166

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Related Party Transactions (Details) (USD $)	3 Months Ended		9 Months Ended				3 Months Ended	9 Months Ended	12 Months Ended					3 Months Ended	9 Months Ended			3 Months Ended			3 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013		Dec. 31, 2013	Sep. 30, 2014 General Partner	Sep. 30, 2014 General Partner	Dec. 31, 2013 General Partner	Sep. 30, 2014 Board of Directors Chairman	Sep. 30, 2014 Chief Executive Officer	Sep. 30, 2014 New Dominion LLC	Dec. 31, 2013 New Dominion LLC	Sep. 30, 2014 Chief Financial Officer	Sep. 30, 2014 Chief Financial Officer	Sep. 30, 2014 General Partner Chief Executive Officer	Sep. 30, 2014 Subordinated Units Board of Directors Chairman	Sep. 30, 2014 MCCS	Sep. 30, 2014 MidCentral Energy Services Chief Executive Officer	Sep. 30, 2014 MidCentral Energy Services President	Sep. 30, 2014 Class B Units	Jun. 30, 2014 Class B Units	Mar. 31, 2014 Class B Units
Related Party Transaction [Line Items]
Ownership percentage of reporting company										25.00%						69.40%
Percentage of common stock owned											5.30%
Percentage of common stock owned										17.20%
Percentage of subordinate units owned										100.00%
Number of subordinate units owned																	2,205,000
Leasehold cost obligations	$ 400,000		$ 400,000			$ 400,000
Charges and fees due to related parties	5,103,000		5,103,000			8,221,000						2,200,000	1,300,000
Service management fees		700,000		1,800,000
General and administrative expense	13,785,000	1,353,000	22,835,000	11,452,000	[1]		500,000	1,100,000
Proceeds from operational advances								1,500,000
Payments for operational advances								1,200,000
Professional fees paid								800,000	400,000					60,000	400,000
Ownership percentage of acquired entity																			36.00%	36.00%
Distributions																					200,000	0	0
Liability assumed in acquisition																		$ 700,000
Ownership percentage in Finley & Cook														31.50%	31.50%

[1] Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

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Goodwill and Intangible Assets (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Finite-Lived Intangible Assets [Line Items]
Change due to purchase price allocation adjustments	$ (3,800,000)	$ (3,836,000)	[1]
Amortization expense	9,400,000	15,600,000
MidCentral Energy Services
Finite-Lived Intangible Assets [Line Items]
Change due to purchase price allocation adjustments	(100,000)
EFS and RPS
Finite-Lived Intangible Assets [Line Items]
Change due to purchase price allocation adjustments	$ (3,700,000)

[1] Includes adjustments totaling $3.8 million during the three months ended September 30, 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. See Note 2 "Acquisitions" for discussion of the purchase price allocation adjustments.

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Derivative Contracts - Commodity Derivative Positions Oil Collars (Details) (Oil Collar)	9 Months Ended
	Sep. 30, 2014 bbl
2014
Derivative [Line Items]
Volumes (Bbls)	23,763
Floor Price (in usd per Bbl)	80.00
Ceiling Price (in usd per Bbl)	103.50
2015
Derivative [Line Items]
Volumes (Bbls)	42,649
Floor Price (in usd per Bbl)	80
Ceiling Price (in usd per Bbl)	93.25

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Equity - Schedule of Distributions (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended
	Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Sep. 30, 2013		Jun. 30, 2013
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	$ 10,406	[1]	$ 9,221	[2]	$ 6,038	[3]	$ 5,252	[3]	$ 2,504	[4]
Common Units
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	9,025	[1]	7,852	[2]	4,681	[3]	3,895	[3]	1,857	[4]
Subordinated Units
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	1,290	[1]	1,279	[2]	1,268	[3]	1,268	[3]	604	[4]
General Partnership Units
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions	$ 91	[1]	$ 90	[2]	$ 89	[3]	$ 89	[3]	$ 43	[4]
Cash Distribution
Schedule of Incentive Distribution Made to Unitholders [Table] [Line Items]
Distributions paid (in usd per unit)	$ 0.585		$ 0.58		$ 0.575		$ 0.575		$ 0.525
Period of Prorated Distribution									47 days

[1] Reflects quarterly distributions of $0.585 per unit paid in the third quarter of 2014.

[2] Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014.

[3] Reflects quarterly distributions of $0.575 per unit paid in the third quarter of 2013 and the first quarter of 2014.

[4] Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.

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Subsequent Events (Details) (USD $)	0 Months Ended		0 Months Ended
	Oct. 21, 2014 Subsequent Event	Oct. 27, 2014 MidCentral Energy Services Subsequent Event	Apr. 29, 2014 Common Units	Oct. 06, 2014 Common Units Subsequent Event	Oct. 03, 2014 Common Units Subsequent Event
Subsequent Event [Line Items]
Aggregate offering price			$ 76,200,000		$ 50,000,000.0
Common partnership units sold in public offering			3,450,000	720,000
Proceeds from sale of common units				16,400,000
Distributions declared (in usd per unit)	$ 0.585
Capital lease obligations		$ 25,000,000

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Property, Plant and Equipment - Schedule of Property and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property and equipment, net	$ 63,281	$ 8,166
Iron
Property, Plant and Equipment [Line Items]
Total	11,212	2,971
Oilfield Services
Property, Plant and Equipment [Line Items]
Total	65,747	8,368
Less: accumulated depreciation	(2,466)	(202)
Property and equipment, net	63,281	8,166
Oilfield Services | Vehicles and Transportation Equipment
Property, Plant and Equipment [Line Items]
Total	15,317	561
Oilfield Services | Machinery and Equipment
Property, Plant and Equipment [Line Items]
Total	38,746	4,757
Oilfield Services | Office Furniture and Equipment
Property, Plant and Equipment [Line Items]
Total	$ 472	$ 79

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Subsequent Events - Schedule of Distributions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended										0 Months Ended		3 Months Ended										0 Months Ended		3 Months Ended										0 Months Ended		3 Months Ended										0 Months Ended
	Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Sep. 30, 2013		Jun. 30, 2013		Oct. 21, 2014 Subsequent Event		Sep. 30, 2014 Common Units		Jun. 30, 2014 Common Units		Mar. 31, 2014 Common Units		Sep. 30, 2013 Common Units		Jun. 30, 2013 Common Units		Oct. 21, 2014 Common Units Subsequent Event		Sep. 30, 2014 Subordinated Units		Jun. 30, 2014 Subordinated Units		Mar. 31, 2014 Subordinated Units		Sep. 30, 2013 Subordinated Units		Jun. 30, 2013 Subordinated Units		Oct. 21, 2014 Subordinated Units Subsequent Event		Sep. 30, 2014 General Partnership Units		Jun. 30, 2014 General Partnership Units		Mar. 31, 2014 General Partnership Units		Sep. 30, 2013 General Partnership Units		Jun. 30, 2013 General Partnership Units		Oct. 21, 2014 General Partnership Units Subsequent Event
Subsequent Event [Line Items]
Distributions	$ 10,406	[1]	$ 9,221	[2]	$ 6,038	[3]	$ 5,252	[3]	$ 2,504	[4]	$ 10,835	[3]	$ 9,025	[1]	$ 7,852	[2]	$ 4,681	[3]	$ 3,895	[3]	$ 1,857	[4]	$ 9,454	[3]	$ 1,290	[1]	$ 1,279	[2]	$ 1,268	[3]	$ 1,268	[3]	$ 604	[4]	$ 1,290	[3]	$ 91	[1]	$ 90	[2]	$ 89	[3]	$ 89	[3]	$ 43	[4]	$ 91	[3]

[1] Reflects quarterly distributions of $0.585 per unit paid in the third quarter of 2014.

[2] Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014.

[3] Reflects quarterly distributions of $0.575 per unit paid in the third quarter of 2013 and the first quarter of 2014.

[4] Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.

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Equity - Allocation of Distributions (Details) (USD $)	9 Months Ended
	Sep. 30, 2014
Minimum Quarterly Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	$ 16,116
Minimum | First Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	18,533
Minimum | Second Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	20,145
Minimum | Third and Thereafter Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	24,174
Maximum | First Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	20,144
Maximum | Second Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distributions	$ 24,173
New Source Energy Partners LP | 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 | First Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	85.00%
New Source Energy Partners LP | Second Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	75.00%
New Source Energy Partners LP | Third and Thereafter Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	50.00%
Class B | Minimum Quarterly Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	0.00%
Class B | First Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	15.00%
Class B | Second Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	25.00%
Class B | Third and Thereafter Target Distribution
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	50.00%

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Fair Value Measurements (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Outstanding balance of line of credit	$ 92,250	$ 78,500
Notes payable	$ 21,889	$ 2,233

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Contingent Consideration (Tables)

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of Business Acquisitions by Acquisition, Contingent Consideration

A reconciliation of the beginning and ending balances of acquisition-related contingent consideration for the three and nine months ended September 30, 2014 is as follows (in thousands):

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Contingent consideration, beginning balance	$	26,609	$	6,320
Acquisition date fair value of contingent consideration - CEU Acquisition	—		—
Acquisition date fair value of contingent consideration - MCCS Acquisition	—		4,057
Acquisition date fair value of contingent consideration - Services Acquisition	4,841		21,984
Change in fair value of contingent consideration	5,404		4,493
Settlement of contingent consideration	—		—
Contingent consideration, ending balance	$	36,854	$	36,854

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Acquisitions - Summary of Assets Acquired and Liabilities Assumed in EFS and RPS Acquisition (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Jun. 26, 2014 EFS and RPS		Jun. 26, 2014 Customer Relationships EFS and RPS		Jun. 26, 2014 Noncompete Agreements EFS and RPS
Business Acquisition [Line Items]
Cash			$ 1,668
Accounts receivable			21,611
Other current assets			620	[1]
Property and equipment			43,853	[1]
Other asset			68,700	[2]	64,200	[3]	4,500	[3]
Goodwill	43,534	23,974	15,397	[1],[4]
Total assets acquired			151,849
Accounts payable and accrued liabilities			(6,047)	[1]
Factoring payable			(15,840)
Long-term debt			(16,800)
Total liabilities assumed			(38,687)
Total net assets			$ 113,162

[1] Includes purchase price allocation adjustments, resulting in an increase totaling $3.7 million to goodwill, during the three months ended September 30, 2014, based on additional information received primarily on other current assets and property and equipment acquired.

[2] 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.

[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] 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. During the three months ended, a purchase price allocation adjustment was made to increase the amount assigned to goodwill by approximately $3.7 million, primarily as a result of an increase to the value of the contingent consideration based on additional information made available.

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Acquisitions - Amounts of Revenues and Revenues in Excess of Direct Operating Expenses Included in Statement of Operations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Business Acquisition [Line Items]
Revenue	$ 56,424	$ 12,431	$ 110,669	$ 32,440
Excess of revenues over direct operating expenses	26,547	8,446	59,568	21,742
Income (loss) from operations	(5,075)	2,121	(815)	(1,541)
2013 Material Acquisitions
Business Acquisition [Line Items]
Revenue		4,197		6,974
Excess of revenues over direct operating expenses		2,180		3,350
2014 Material Acquisitions
Business Acquisition [Line Items]
Revenue	30,110		35,047
Income (loss) from operations	$ 590		$ 2,786

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Equity (Details) (USD $)	0 Months Ended	3 Months Ended		9 Months Ended		0 Months Ended	3 Months Ended			9 Months Ended					0 Months Ended	9 Months Ended	0 Months Ended
	Apr. 29, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jun. 26, 2014 EFS and RPS	Sep. 30, 2014 Class B Units	Jun. 30, 2014 Class B Units	Mar. 31, 2014 Class B Units	Sep. 30, 2014 First Target Distribution Maximum	Sep. 30, 2014 First Target Distribution Class B Units	Sep. 30, 2014 Second Target Distribution Maximum	Sep. 30, 2014 Second Target Distribution Class B Units	Sep. 30, 2014 Third and Thereafter Target Distribution Class B Units	Apr. 29, 2014 Common Units	Sep. 30, 2014 Common Units	Jun. 26, 2014 Common Units Phantom Units EFS and RPS	Jun. 26, 2014 Common Units Phantom Units EFS and RPS Service Requirement Units	Jun. 26, 2014 Common Units Phantom Units EFS and RPS Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Issuance of common units in acquisitions (in units)						1,411,777										1,964,957
Common partnership units sold in public offering															3,450,000
Unit price of units sold in public offering															$ 23.25
Proceeds from public offering of common partnership units															$ 76,200,000
Underwriter's fees associated with public sale of common units															3,600,000
Offering costs associated with public sale of common units															300,000
Net proceeds from offering used to repay credit facility	5,000,000
Days after quarter end in which distributions are declared and distributed				45 days
Increasing distribution percentage associated with Class B Units											15.00%		25.00%	50.00%
Distributions							200,000	0	0	20,144		24,173
Equity-based compensation expense		1,300,000	0	1,906,000	7,738,000
Phantom units granted (in units)																	432,038	401,171
Value of phantom units granted																	9,400,000
Compensation expense					400,000
Phantom unit vesting period																			2 years
Fair value of units granted																	$ 8,200,000

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Acquisitions (Details) (USD $)	3 Months Ended		9 Months Ended					9 Months Ended	0 Months Ended		1 Months Ended				3 Months Ended	9 Months Ended	1 Months Ended				1 Months Ended		3 Months Ended			1 Months Ended				1 Months Ended		0 Months Ended			0 Months Ended			0 Months Ended	9 Months Ended				0 Months Ended		0 Months Ended		3 Months Ended		0 Months Ended		9 Months Ended					3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013	Jun. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Common Units	Nov. 12, 2013 Chief Executive Officer MidCentral Energy Services	Nov. 30, 2013 Chief Executive Officer MidCentral Energy Services	Mar. 31, 2013 March Acquired Properties	May 31, 2013 May Acquired Properties	Jul. 31, 2013 July Acquired Properties	Jul. 31, 2013 Orion Acquisition	Sep. 30, 2013 2013 Material Acquisitions	Sep. 30, 2013 2013 Material Acquisitions	Oct. 31, 2013 Southern Dome producing_well	Sep. 30, 2014 Southern Dome	Dec. 31, 2013 Southern Dome	Oct. 04, 2013 Southern Dome	Nov. 30, 2013 MidCentral Energy Services		Sep. 30, 2014 MidCentral Energy Services	Dec. 31, 2013 MidCentral Energy Services	Nov. 12, 2013 MidCentral Energy Services	Nov. 30, 2013 MidCentral Energy Services Customer Relationships		Sep. 30, 2014 MidCentral Energy Services Maximum	Nov. 30, 2013 MidCentral Energy Services Maximum	Nov. 30, 2013 MidCentral Energy Services MCE Owners	Nov. 30, 2013 MidCentral Energy Services Select MCE Employees	Jan. 31, 2014 CEU Paradigm producing_well		Sep. 30, 2014 CEU Paradigm	Jun. 26, 2014 MCCS		Sep. 30, 2014 MCCS	Jun. 26, 2014 MCCS Chief Executive Officer	Sep. 30, 2014 MCCS Customer Relationships	Sep. 30, 2014 MCCS Maximum	Jun. 26, 2014 MCCS Maximum	Jun. 26, 2014 EFS	Jun. 26, 2014 EFS EFS Employees	Jun. 26, 2014 RPS	Jun. 26, 2014 EFS and RPS		Sep. 30, 2014 EFS and RPS		Jun. 26, 2014 EFS and RPS Phantom Units Common Units	Jun. 26, 2014 EFS and RPS Service Requirement Units Phantom Units Common Units	Sep. 30, 2014 EFS and RPS Customer Relationships	Jun. 26, 2014 EFS and RPS Customer Relationships		Jun. 26, 2014 EFS and RPS Noncompete Agreements		Sep. 30, 2014 2014 Material Acquisitions	Sep. 30, 2014 2014 Material Acquisitions	Sep. 30, 2014 2014 Material Acquisitions Acquisition-related Costs	Sep. 30, 2013 2014 Material Acquisitions Acquisition-related Costs
Business Acquisition [Line Items]
Total fair value of consideration											$ 28,000,000	$ 7,900,000	$ 4,900,000	$ 3,200,000			$ 14,468,000				$ 68,170,000											$ 17,124,000			$ 6,355,000										$ 113,162,000
Units issued in acquisition (in units)											1,378,500																			1,847,265	99,768
Value of units issued in acquisition (in usd per unit)											$ 20.30						$ 20.79													$ 22.64	$ 22.64	$ 23.78			$ 23.45								$ 23.45		$ 23.45
Percentage of working interest acquired													10.00%
Acquisition expense															500,000	1,000,000
Issuance of common units in acquisitions (in units)								1,964,957									414,045															488,667			33,646								30,867		1,411,777
Equity interest percentage acquired in acquisition																					100.00%														100.00%							100.00%		100.00%
Contingent consideration	36,854,000		36,854,000			26,609,000	6,320,000											0	0	1,600,000	6,320,000	[1]	15,400,000	6,300,000	6,320,000			120,000,000	120,000,000.0			0	[2]	0	4,057,000	[3]	437,000			4,500,000.0	4,500,000.0				21,984,000	[4]	21,053,000	[4]
Class B units issued in MCE acquisition																					13,988,000	[5]
Useful life of finite-lived intangible asset																										7 years													7 years												7 years
Ownership percentage of acquired entity										36.00%																												50.00%
Equity method carrying basis in acquisition									1,800,000																													100,000
Gain on acquisition of business	0	0	2,298,000		0																22,700,000														2,300,000
Number of wells Company in which company has acquired working interests																	25															23
Phantom units granted (in units)																																																	432,038	401,171
Purchase price adjustment related to goodwill	3,800,000		3,836,000	[6]																			100,000																								3,700,000
Intangible Asset																										36,772,000	[7]								1,700,000	[8]									68,700,000	[9]						64,200,000	[7]	4,500,000	[7]
Acquisition costs and transaction bonuses																																																								$ 400,000	$ 3,600,000	$ 24,300,000	$ 1,600,000

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

[2] The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period (the "CEU Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

[3] The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 3 "Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

[4] The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 3 "Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. During the three months ended September 30, 2014, a purchase price allocation adjustment was made for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

[5] Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See Note 9 "Equity" for additional discussion of these incentive distributions. The Class B units were valued at $14.0 million at the acquisition date through the use of a Monte Carlo simulation.

[6] Includes adjustments totaling $3.8 million during the three months ended September 30, 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. See Note 2 "Acquisitions" for discussion of the purchase price allocation adjustments.

[7] Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

[8] 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

[9] Identifiable intangible assets include $64.2 million for customer relationships and $4.5 million for non-compete agreements. Customer relationships were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years. Non-compete agreements were valued based on an income approach and are amortized over the agreement period.

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Contingent Consideration - Reconciliation of Acquisition Related Accrued Earnouts (Details) (USD $)	3 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended			3 Months Ended	9 Months Ended			3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 CEU Paradigm	Sep. 30, 2014 CEU Paradigm	Jan. 31, 2014 CEU Paradigm		Sep. 30, 2014 MCCS	Sep. 30, 2014 MCCS	Jun. 26, 2014 MCCS		Sep. 30, 2014 EFS and RPS		Sep. 30, 2014 EFS and RPS		Jun. 26, 2014 EFS and RPS
Business Acquisition, Contingent Consideration [Roll Forward]
Contingent consideration, beginning balance	$ 26,609,000	$ 6,320,000				$ 0	[1]			$ 4,057,000	[2]					$ 21,984,000	[3]
Acquisition date fair value of contingent consideration		4,493,000	0	0	0			0	4,057,000			4,841,000		21,984,000
Change in fair value of contingent consideration	5,404,000	4,493,000						(3,700,000)				(900,000)
Settlement of contingent consideration	0	0
Contingent consideration, ending balance	$ 36,854,000	$ 36,854,000		$ 0	$ 0	$ 0	[1]	$ 437,000	$ 437,000	$ 4,057,000	[2]	$ 21,053,000	[3]	$ 21,053,000	[3]	$ 21,984,000	[3]

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

[2] The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 3 "Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

[3] The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 3 "Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. During the three months ended September 30, 2014, a purchase price allocation adjustment was made for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

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Derivative Contracts - Gains (Losses) on Derivative Contracts (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gain (loss) on derivative contracts, net	$ 3,768	[1]	$ (3,453)	[1]	$ (760)	[1]	$ (2,597)	[1]

[1] Included in gain (loss) on derivative contracts for the three months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $0.3 million and $0.5 million, respectively. Included in loss on derivative contracts for the nine months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $3.8 million and $0.9 million, respectively.

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Derivative Contracts - Commodity Derivative Positions Natural Gas Options (Details) (Natural Gas Options)	9 Months Ended
	Sep. 30, 2014 MMBTU
2014
Derivative [Line Items]
Volumes (MMBtu)	99,034
Floor Price (in usd per MMBtu)	3.5
2015
Derivative [Line Items]
Volumes (MMBtu)	798,853
Floor Price (in usd per MMBtu)	3.5
2016
Derivative [Line Items]
Volumes (MMBtu)	930,468
Floor Price (in usd per MMBtu)	3.5

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Acquisitions - Purchase Price Allocation for MCCS Acquisition (Details) (USD $)				0 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Jun. 26, 2014 MCCS		Sep. 30, 2014 MCCS
Business Acquisition [Line Items]
Fair value of common units granted				$ 789,000	[1]
Contingent consideration	36,854,000	26,609,000	6,320,000	4,057,000	[2]	437,000
Noncontrolling interest	15,497,000		13,988,000	1,509,000	[3]
Total fair value of consideration				$ 6,355,000

[1] The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition).

[2] The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 3 "Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

[3] As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.

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Contingent Consideration

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Contingent Consideration

Contingent Consideration

The contingent consideration provided for in certain of our acquisitions represents additional consideration. The fair value of such contingent consideration is estimated using various inputs, including the probability that targets for additional payout will be met, as described below. As the significant inputs to determine fair value of the contingent consideration represent significant unobservable inputs, they are classified as Level 3 under the fair value hierarchy described in Note 7 "Fair Value Measurements."

A reconciliation of the beginning and ending balances of acquisition-related contingent consideration for the three and nine months ended September 30, 2014 is as follows (in thousands):

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
Contingent consideration, beginning balance	$	26,609	$	6,320
Acquisition date fair value of contingent consideration - CEU Acquisition	—		—
Acquisition date fair value of contingent consideration - MCCS Acquisition	—		4,057
Acquisition date fair value of contingent consideration - Services Acquisition	4,841		21,984
Change in fair value of contingent consideration	5,404		4,493
Settlement of contingent consideration	—		—
Contingent consideration, ending balance	$	36,854	$	36,854

Southern Dome Contingent Consideration. In conjunction with the acquisition of the Southern Dome Acquired Properties, the Partnership agreed to provide additional consideration to Scintilla if the average daily production attributable to the Southern Dome Acquired Properties for the nine months ending September 30, 2014 exceeds 383.5 Boe. The contingent consideration was determined to have a fair value of $1.6 million at the acquisition date and was included in the consideration for the Southern Dome Acquired Properties. The Partnership estimated the fair value as of December 31, 2013 at $0. As detailed in the acquisition agreement, the additional consideration was calculated as the value of average daily production for the nine months ending September 30, 2014 less (i) the asset value, (ii) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (iii) revenue attributable to any wells located in a specified project area that were not producing in paying quantities as of the effective date of the acquisition. Any change to the fair value of the contingent consideration was adjusted through earnings due to the factors impacting the ultimate payout. Based on actual production levels for the nine months ending September 30, 2014, no additional consideration is due to Scintilla.

MCE Contingent Consideration. The former owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE, excluding EFS, RPS and MCCS, for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $120.0 million cap. The contingent consideration was valued at $6.3 million at the acquisition date and was included in the consideration for the MCE Acquisition. Any change to the fair value of the contingent consideration is adjusted through earnings. Based on projections for MCE, the Partnership estimated fair value of the MCE Contingent Consideration as of September 30, 2014 and December 31, 2013 was approximately $15.4 million and $6.3 million, respectively, which is presented as contingent consideration payable in the accompanying unaudited condensed consolidated balance sheets. The increase in fair value of approximately $10.0 million and $9.1 million is included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014, respectively.

CEU Contingent Consideration. In conjunction with the CEU Acquisition, the Partnership agreed to provide additional consideration to CEU if the average daily production attributable to the acquired working interest for the nine months ending September 30, 2014 exceeds 566.0 Boe. The CEU Contingent Consideration was determined to have no value at the acquisition date. As detailed in the acquisition agreement, the additional consideration was calculated as the acquisition value of the production increase less (i) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells located in a specified project area that were not producing in paying quantities as of the effective date of the acquisition. Based on actual production levels for the nine months ending September 30, 2014, no additional consideration is due to CEU.

MCCS Contingent Consideration. The former owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $4.5 million cap. The contingent consideration was valued at $4.1 million at the acquisition date and was included in the consideration for the MCCS Acquisition. Any changes to the fair value of the contingent consideration will be adjusted through earnings. The fair value of the contingent consideration was $0.4 million as of September 30, 2014. The decrease in fair value of approximately $3.7 million is included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014.

EFS/RPS Contingent Consideration. The former owners of EFS and RPS are entitled to receive additional consideration in the form of cash and common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments. The terms of the contribution agreement provide that the additional consideration is to be paid approximately 50% in cash and approximately 50% in common units, consistent with the initial consideration for the Services Acquisition. However, the former owners can elect to receive a larger portion of the payout in common units. The contingent consideration was valued at $22.0 million as of the acquisition date and was included in the consideration for the Services Acquisition. Any change to the fair value of the contingent consideration will be adjusted through earnings. The fair value of the contingent consideration was $21.1 million as of September 30, 2014. The decrease in fair value of approximately $0.9 million is included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014.

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Derivative Contracts - Commodity Derivative Positions Natural Gas Liquid Options (Details) (Natural Gas Liquid Options, 2014)	9 Months Ended
	Sep. 30, 2014 bbl
Natural Gas Liquid Options | 2014
Derivative [Line Items]
Volumes (Bbls)	5,535
Average Floor Price (in usd per Bbl)	63.19

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Acquisitions - Purchase Price Allocation for Southern Dome Acquisition (Details) (Southern Dome, USD $) In Thousands, unless otherwise specified	1 Months Ended
	Oct. 31, 2013
Southern Dome
Consideration:
Cash	$ 4,260
Fair value of common units granted	8,608	[1]
Contingent consideration	1,600	[2]
Total fair value of consideration	14,468
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	15,190
Asset retirement obligations	(170)
Other liabilities	(552)
Total net assets	$ 14,468

[1] The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).

[2] The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideratio

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Goodwill and Intangible Assets (Tables)

9 Months Ended

Sep. 30, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill

A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2013 to September 30, 2014 is as follows (in thousands):

Goodwill at December 31, 2013	$	23,974
Additions:
MCCS Acquisition	4,060
Services Acquisition	11,664
Change due to purchase price allocation adjustments (1)	3,836
Goodwill at September 30, 2014	$	43,534

__________

(1)    Includes adjustments totaling $3.8 million during the three months ended September 30, 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. See Note 2 "Acquisitions" for discussion of the purchase price allocation adjustments.

Schedule of Finite-Lived Intangible Assets

The Partnership's intangible assets at September 30, 2014 and December 31, 2013 consist of the following (in thousands):    

	September 30, 2014		December 31, 2013
Customer relationships - MCE Acquisition	$	36,772	$	36,772
Customer relationships - Services Acquisition	64,200		—
Non-compete agreements - Services Acquisition	4,500		—
Customer relationships - MCCS Acquisition	1,700		—
Total intangible assets	107,172		36,772
Less: accumulated amortization	17,359		1,763
Intangible assets, net	$	89,813	$	35,009

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table summarizes our derivative contracts on a gross basis, the effects of netting assets and liabilities for which the right of offset exists (in thousands):

September 30, 2014	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,065	$	(404	)	$	661
Commodity derivatives - long-term assets	565		(6		)	559
Total	$	1,630	$	(410	)	$	1,220
Liabilities:
Commodity derivatives - current liabilities	$	1,012	$	(404	)	$	608
Commodity derivatives - long-term liabilities	43		(6		)	37
Total	$	1,055	$	(410	)	$	645

December 31, 2013	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,342	$	(1,212	)	$	130
Commodity derivatives - long-term assets	1,638		(978		)	660
Total	$	2,980	$	(2,190	)	$	790
Liabilities:
Commodity derivatives - current liabilities	$	4,379	$	(1,212	)	$	3,167
Commodity derivatives - long-term liabilities	1,015		(978		)	37
Total	$	5,394	$	(2,190	)	$	3,204

The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended September 30, 2013 and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,			Nine Months Ended September 30,
	2013			2014			2013
Beginning balance	$	1,866		$	(2,517	)	$	(112	)
Loss on derivative contracts	(3,277		)	(2,432		)	(1,522		)
Transfers out (1)	—			2,843			—
Cash paid upon settlement	446			2,106			669
Ending balance	$	(965	)	$	—		$	(965	)
Unrealized losses included in earnings relating to derivatives held at period end	$	(2,677	)	$	—		$	(884	)

The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis (in thousands):

September 30, 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	$	—	$	157		$	—		$	157
Oil, natural gas and NGL put options	—		539			—			539
Oil, natural gas and NGL fixed price swaps	—		(121		)	—			(121		)
Contingent consideration	—		—			(36,854		)	(36,854		)
Total	$	—	$	575		$	(36,854	)	$	(36,279	)

December 31, 2013	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
Oil collars	$	—	$	(57	)	$	—		$	(57	)
Natural gas collars	—		—			(9		)	(9		)
Oil put options	—		28			—			28
Natural gas and NGL put options	—		—			403			403
Oil and natural gas fixed price swaps	—		132			—			132
NGL fixed price swaps	—		—			(2,911		)	(2,911		)
Contingent consideration	—		—			(6,320		)	(6,320		)
Total	$	—	$	103		$	(8,837	)	$	(8,734	)

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Factoring Payable (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Factoring Payable [Line Items]
Factoring payable	$ 15,526	$ 1,907
Percentage of funding from factoring payable received upfront	90.00%
Percentage of balance of payables factored that is reserved	10.00%
Days till outstanding factored payable are repurchased	90 days
London Interbank Offered Rate (LIBOR)
Factoring Payable [Line Items]
Interest margin on factoring payables	3.00%

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Acquisitions - Purchase Price Allocation for MCE Acquisition (Details) (USD $)				1 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Nov. 30, 2013 MidCentral Energy Services		Sep. 30, 2014 MidCentral Energy Services	Dec. 31, 2013 MidCentral Energy Services	Nov. 12, 2013 MidCentral Energy Services	Nov. 30, 2013 MCE Owners MidCentral Energy Services		Nov. 30, 2013 Select MCE Employees MidCentral Energy Services
Business Acquisition [Line Items]
Cash				$ 3,781,000
Fair value of units granted									41,822,000	[1]	2,259,000	[2]
Contingent consideration	36,854,000	26,609,000	6,320,000	6,320,000	[3]	15,400,000	6,300,000	6,320,000
Class B units issued in MCE acquisition				13,988,000	[4]
Total fair value of consideration				$ 68,170,000

[1] The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).

[2] The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnership’s long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.

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

[4] Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See Note 9 "Equity" for additional discussion of these incentive distributions. The Class B units were valued at $14.0 million at the acquisition date through the use of a Monte Carlo simulation.

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Equity (Tables)

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Schedule of Distributions Made to Units

The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common, subordinated and general partner units during the three and nine months ended September 30, 2014 and 2013, as shown in the following table (in thousands):

Distributions	Common Units		Subordinated Units		General Partner Units		Total
2014
First Quarter (1)	$	4,681	$	1,268	$	89	$	6,038
Second Quarter (2)	$	7,852	$	1,279	$	90	$	9,221
Third Quarter (3)	$	9,025	$	1,290	$	91	$	10,406
2013
Second Quarter (4)	$	1,857	$	604	$	43	$	2,504
Third Quarter (1)	$	3,895	$	1,268	$	89	$	5,252

__________

(1)    Reflects quarterly distributions of $0.575 per unit paid in the third quarter of 2013 and the first quarter of 2014.

(2)    Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014.

(3)    Reflects quarterly distributions of $0.585 per unit paid in the third quarter of 2014.

(4)    Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.

The following distributions will be paid on November 14, 2014 to holders of record as of the close of business on November 3, 2014 (in thousands):

	Common Units		Subordinated Units		General Partner Units		Total
Distributions	$	9,454	$	1,290	$	91	$	10,835

Schedule of Target Distributions to Unitholders

The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels, as adjusted based on the MCCS Acquisition.

				Marginal Percentage Interest in  Distributions
	Total Quarterly Distributions per MCE Unit			MCE Class A Unitholders (the Partnership)	MCE Class B Unitholders
Minimum Quarterly Distribution	$16,116			100%	—%
First Target Distribution	$18,533	to	$20,144	85%	15%
Second Target Distribution	$20,145	to	$24,173	75%	25%
Third Target Distribution and Thereafter	$24,174	and above		50%	50%

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Earnings per Unit - (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

Basic and diluted earnings per unit for the three and nine months ended September 30, 2014 and 2013 were computed as follows (in thousands, except per unit amounts):

	Three Months Ended   September 30, 2014									Nine Months Ended   September 30, 2014
	Common Units			Subordinated Units			General Partner			Common Units			Subordinated Units			General Partner
Net loss	$	(2,599	)	$	(371	)	$	(26	)	$	(2,503	)	$	(411	)	$	(29	)
Weighted average units outstanding	15,429			2,205			155			12,646			2,205			155
Basic and diluted loss per unit	$	(0.17	)	$	(0.17	)	$	(0.17	)	$	(0.20	)	$	(0.19	)	$	(0.19	)

	Three Months Ended   September 30, 2013									Nine Months Ended   September 30, 2013
	Common Units			Subordinated Units			General Partner			Common Units			Subordinated Units			General Partner
Net loss (1)	$	(1,473	)	$	(479	)	$	(34	)	$	(76	)	$	(430	)	$	(29	)
Weighted average units outstanding	6,774			2,205			155			6,480			2,205			155
Basic and diluted loss per unit	$	(0.22	)	$	(0.22	)	$	(0.22	)	$	(0.01	)	$	(0.20	)	$	(0.19	)

__________

(1) Reflects net loss from February 13, 2013 through September 30, 2013 for the nine months ended September 30, 2013.

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Acquisitions

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Acquisitions

Acquisitions

The Partnership completed acquisitions during 2013 and 2014, as described below. Certain of the 2013 acquisitions increased the Partnership's portfolio of oil and natural gas properties. The acquisitions of MCE, Erick Flowback Services LLC ("EFS"), Rod's Production Services, L.L.C. ("RPS") and MidCentral Completion Services, LLC ("MCCS") established the Partnership's oilfield services segment, which helps to facilitate the Partnership's goals of becoming a more fully integrated oil and natural gas partnership. With the exception of the acquisition of oil and natural gas properties from Orion Exploration Partners, LLC, all of the 2013 acquisitions were with related parties. The acquisition of MCCS was the only acquisition in 2014 with related parties. See Note 11 "Related Party Transactions."

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy as described in Note 7 "Fair Value Measurements." Fair value may be estimated using comparable market data, a discounted cash flow method, or another method as discussed below. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of applicable sales estimates, operational costs and a risk-adjusted discount rate. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. Fair value of MCCS' inventory acquired was determined based on a comparative sales approach. Fair value for intangible assets acquired was primarily determined using a discounted cash flow model or multi-period excess earnings model under the income approach, which factors in discount rates, probability factors and forecasts. The fair values of property, plant and equipment acquired were primarily based on a cost approach using an indirect cost methodology to determine replacement cost. The inputs, as noted above, used to determine fair value required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Carrying value for current assets and liabilities acquired is typically representative of fair value due to their short term nature.

2013 Acquisitions

March Acquired Properties.In March 2013, we acquired certain oil and natural gas properties located in the Golden Lane and Luther fields in Oklahoma from New Source, Scintilla, and W.K. Chernicky, LLC, for an aggregate adjusted purchase price of approximately $28.0 million (the "March Acquired Properties"). As consideration, the Partnership issued 1,378,500 common units valued at $20.30 per unit.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	29,049
Other assets	754
Asset retirement obligations	(1,333		)
Other liabilities	(488		)
Total net assets	$	27,982

May Acquired Properties.In May 2013, the Partnership completed an acquisition of certain oil and natural gas properties located in Oklahoma from NSEC for approximately $7.9 million, net of purchase price adjustments (the "May Acquired Properties").

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	8,165
Asset retirement obligations	(19		)
Other liabilities	(254		)
Total net assets	$	7,892

July Scintilla Acquired Properties.In July 2013, the Partnership completed an acquisition of a 10% working interest in certain oil and natural gas properties located in Oklahoma from Scintilla for approximately $4.9 million, net of purchase price adjustments.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	4,888
Asset retirement obligations	(4		)
Other liabilities	(18		)
Total net assets	$	4,866

Orion Acquired Properties.In July 2013, the Partnership acquired certain oil and natural gas properties located in Oklahoma from Orion Exploration Partners, LLC for approximately $3.2 million, net of purchase price adjustments.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	3,274
Asset retirement obligations	(24		)
Other liabilities	(20		)
Total net assets	$	3,230

The amounts of revenues and excess of revenues over direct operating expenses included in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013 generated by the March Acquired Properties, the May Acquired Properties, the July Scintilla Acquired Properties and the Orion Acquired Properties are shown in the table below. Direct operating expenses include lease operating expenses and production taxes.

	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
	(in thousands)
Revenue	$	4,197	$	6,974
Excess of revenues over direct operating expenses	$	2,180	$	3,350

Acquisition expense related to the acquisitions as of September 30, 2013 of $0.5 million and $1.0 million were included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2013, respectively.

Southern Dome Acquired Properties.In October 2013, the Partnership completed the acquisition of working interests in 25 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma (the "Southern Dome Acquired Properties") from Scintilla for total consideration of $14.5 million, net of purchase price adjustments.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Consideration:
Cash	$	4,260
Fair value of common units granted (1)	8,608
Contingent consideration (2)	1,600
Total fair value of consideration	$	14,468
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	15,190
Asset retirement obligations	(170		)
Other liabilities	(552		)
Total net assets	$	14,468

__________

(1) The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).

(2) The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideration.

MCE Acquisition.In November 2013, the Partnership acquired 100% of the equity interests in MCE, other than Class B Units that were retained by certain of the sellers as discussed further below (the "MCE Acquisition"). MidCentral Energy Services, LLC ("MCES"), a wholly owned subsidiary of MCE, operates an oilfield services business that offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region and in South Texas and West Texas, along with the rental of certain ancillary equipment necessary to perform such services.

Total consideration for the MCE Acquisition is as follows (in thousands):

Consideration:
Cash	$	3,781
Fair value of common units granted (1)	41,822
Common units granted to MCE employees (2)	2,259
Contingent consideration (3)	6,320
MCE Class B units granted (4)	13,988
Total fair value of consideration	$	68,170

__________

(1) The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).

(2) The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnership’s long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.

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

(4) Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See Note 9 "Equity" for additional discussion of these incentive distributions. The Class B units were valued at $14.0 million at the acquisition date through the use of a Monte Carlo simulation.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	1,522
Accounts receivable	3,365
Other current assets	954
Property and equipment	7,923
Intangible asset (1)	36,772
Goodwill (2) (3)	24,077
Other assets	19
Total assets acquired	74,632
Accounts payable and accrued liabilities (3)	(2,448		)
Factoring payable	(1,679		)
Long-term debt	(2,335		)
Total liabilities assumed	(6,462		)
Net assets acquired	$	68,170

__________

(1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

(2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.

(3) Includes purchase price allocation adjustment of $0.1 million made during the three months ended September 30, 2014 based on additional information received on accounts payable assumed.

Since the President and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos, through his control over the Partnership’s general partner, controls the Partnership and also owned 36% of the equity interest in MCE, the MCE Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 36% equity interest in MCE acquired from Mr. Kos at his equity method carrying basis, which was $1.8 million as of November 12, 2013. The Partnership remeasured the 36% interest to determine the acquisition-date fair value and recognized a corresponding gain of $22.7 million on investment in acquired business.

2014 Acquisitions

CEU Acquisition.On January 31, 2014, we completed the acquisition of working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma, from CEU Paradigm, LLC ("CEU") for approximately $17.1 million, net of purchase price adjustments (the "CEU Acquisition").

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition, net of purchase price adjustments, is as follows (in thousands):

Consideration:
Cash	$	5,503
Fair value of common units granted (1)	11,621
Contingent consideration (2)	—
Total fair value of consideration	$	17,124
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	17,306
Asset retirement obligations	(182		)
Total net assets	$	17,124

__________

(1) The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition).

(2) The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period (the "CEU Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

MCCS Acquisition. On June 26, 2014, we exercised the option granted in connection with the MCE Acquisition to acquire 100% of the equity interest in MCCS, an oilfield services company that specializes in providing services, primarily installation and pressure testing, to oil and natural gas exploration and production companies (the "MCCS Acquisition").

Total consideration for the MCCS Acquisition is as follows (in thousands):

Consideration:
Fair value of common units granted (1)	$	789
Contingent consideration (2)	4,057
Noncontrolling interest (3)	1,509
Total fair value of consideration	$	6,355

__________

(1) The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition).

(2) The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 3 "Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

(3) As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	109
Accounts receivable	524
Inventory	2,035
Other current assets	14
Property and equipment	107
Intangible asset (1)	1,700
Goodwill (2)	4,060
Other assets	28
Total assets acquired	8,577
Accounts payable and accrued liabilities	(1,431		)
Long-term debt	(791		)
Total liabilities assumed	(2,222		)
Net assets acquired	$	6,355

__________

(1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

(2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS's business. Goodwill has been allocated to the oilfield services segment.

Since the President and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos, through his control over the Partnership’s general partner, controls the Partnership and also owned 50% of the equity interest in MCCS, the MCCS Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 50% equity interest in MCCS acquired from Mr. Kos at his equity method carrying basis, which was $0.1 million as of June 26, 2014. The Partnership remeasured the 50% interest to determine the acquisition-date fair value and recognized a corresponding gain of $2.3 million on investment in acquired business.

Services Acquisition.On June 26, 2014, the Partnership acquired 100% of the outstanding membership interests in EFS and 100% of the outstanding membership interests in RPS for total consideration of approximately $113.2 million (the "Services Acquisition"). EFS and RPS, which are affiliated entities, are oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry.

Total consideration for the Services Acquisition is as follows (in thousands):

Consideration:
Cash	$	57,348
Fair value of common units granted (1)	33,106
Common units granted for the benefit of EFS and RPS employees (2)	724
Contingent consideration (3)	21,984
Total fair value of consideration	$	113,162

__________

(1) The fair value of the unit consideration was based upon 1,411,777 common units valued at $23.45 per unit (closing price on the date of the acquisition).

(2) The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition are excluded from consideration based on the future service requirement for vesting. See Note 9 "Equity" for additional discussion of phantom units.

(3) The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 3 "Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. During the three months ended September 30, 2014, a purchase price allocation adjustment was made for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	1,668
Accounts receivable	21,611
Other current assets (1)	620
Property and equipment (1)	43,853
Intangible assets (2)	68,700
Goodwill (1) (3)	15,397
Total assets acquired	151,849
Accounts payable and accrued liabilities (1)	(6,047		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,687		)
Net assets acquired	$	113,162

__________

(1) Includes purchase price allocation adjustments, resulting in an increase totaling $3.7 million to goodwill, during the three months ended September 30, 2014, based on additional information received primarily on other current assets and property and equipment acquired.

(2) 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.

(3) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the 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. During the three months ended, a purchase price allocation adjustment was made to increase the amount assigned to goodwill by approximately $3.7 million, primarily as a result of an increase to the value of the contingent consideration based on additional information made available.

Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the nine months ended September 30, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013. The pro forma combined results of operations for the nine months ended September 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 an acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

	Nine Months Ended September 30, 2014
	(in thousands, except per unit amounts)
Revenue	$	172,590
Net income attributable to New Source Energy Partners L.P. (1)	$	5,084
Net income per common unit (1):
Basic	$	0.31
Diluted	$	0.31

__________

(1) Excludes $24.3 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.

The amounts of revenues and operating income included in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 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 revenue over direct operating expenses and does not reflect certain expenses, such as general and administrative; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. Direct operating expenses include lease operating expenses and production taxes for the CEU Acquisition.

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
	(in thousands)
Revenue	$	30,110	$	35,047
Operating income	$	590	$	2,786

Acquisition expense for the 2014 Material Acquisitions of $0.4 million and $3.6 million were included in general and administrative expenses in the accompanying unaudited statements of operations for the three and nine months ended September 30, 2014, respectively.

The following unaudited pro forma combined results of operations are presented for the three and nine months ended September 30, 2013 as though the Partnership completed the acquisitions of the March Acquired Properties, the Southern Dome Acquired Properties and the MCE Acquisition (collectively, the "2013 Material Acquisitions") as of January 1, 2012, which was the beginning of the earliest period presented at the time of the acquisition, and the 2014 Material Acquisitions, as of January 1, 2013. The pro forma combined results of operations for the three and nine months ended September 30, 2013 have been prepared by adjusting the historical results of the Partnership to include the historical results of these acquisitions through the date of acquisition and estimates of the effect of the 2013 Material Acquisitions and the 2014 Material Acquisitions on the combined results. In addition, pro forma adjustments have been made for the interest that would have been incurred for financing the cash portion of the consideration of the 2013 Material Acquisitions with the Partnership's senior secured revolving credit facility and assume the units issued as consideration for the 2013 Material Acquisitions had been outstanding since January 1, 2012 and the units issued as consideration for the 2014 Material Acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund an acquisition, had been outstanding since January 1, 2013.

	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
	(in thousands, except per unit amounts)
Revenue	$	65,673		$	136,851
Net loss attributable to New Source Energy Partners L.P. (1)	$	(3,971	)	$	(10,647	)
Net loss per common unit (1):
Basic	$	(0.24	)	$	(0.83	)
Diluted	$	(0.24	)	$	(0.83	)

__________

(1)    Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the nine months ended September 30, 2013.

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Producing overhead and supervision charges	$	624	$	464	$	2,080	$	1,277
Drilling and completion supervision charges	60		119		230		246
Saltwater disposal fees	260		329		1,075		502
Total expenses incurred	$	944	$	912	$	3,385	$	2,025

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Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligation at December 31, 2013			$ 3,455
Liability incurred upon acquiring and drilling wells			235
Liability settled or disposed			(32)
Accretion	77	59	219	145
Asset retirement obligation at September 30, 2014	$ 3,877		$ 3,877

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

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Contingent Consideration (Details) (USD $)	3 Months Ended	9 Months Ended								9 Months Ended			9 Months Ended			3 Months Ended			3 Months Ended								3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 MidCentral Energy Services	Dec. 31, 2013 MidCentral Energy Services	Nov. 30, 2013 MidCentral Energy Services		Nov. 12, 2013 MidCentral Energy Services	Sep. 30, 2014 Southern Dome Boe	Dec. 31, 2013 Southern Dome	Oct. 04, 2013 Southern Dome	Sep. 30, 2014 CEU Paradigm Boe	Jan. 31, 2014 CEU Paradigm		Sep. 30, 2014 MCCS	Jun. 26, 2014 MCCS		Sep. 30, 2014 EFS and RPS		Jun. 26, 2014 EFS and RPS		Sep. 30, 2014 Maximum MidCentral Energy Services	Nov. 30, 2013 Maximum MidCentral Energy Services	Sep. 30, 2014 Maximum MCCS	Jun. 26, 2014 Maximum MCCS	Sep. 30, 2014 General and Administrative Expenses MidCentral Energy Services	Sep. 30, 2014 General and Administrative Expenses MidCentral Energy Services	Sep. 30, 2014 General and Administrative Expenses MCCS	Sep. 30, 2014 General and Administrative Expenses EFS and RPS
Business Acquisition [Line Items]
Average daily production needed to provide additional consideration for acquisition (in Boe per day)										383.5			566.0
Contingent consideration	$ 36,854,000	$ 36,854,000	$ 26,609,000	$ 6,320,000	$ 15,400,000	$ 6,300,000	$ 6,320,000	[1]	$ 6,320,000	$ 0	$ 0	$ 1,600,000	$ 0	$ 0	[2]	$ 437,000	$ 4,057,000	[3]	$ 21,053,000	[4]	$ 21,984,000	[4]	$ 120,000,000	$ 120,000,000.0	$ 4,500,000.0	$ 4,500,000.0
Change in fair value of contingent consideration	$ (5,404,000)	$ (4,493,000)														$ 3,700,000			$ 900,000								$ 10,000,000	$ 9,100,000	$ 3,700,000	$ 900,000
Percentage of contingent consideration to be paid in cash																					50.00%	[4]
Percentage of contingent consideration to be paid in common units																					50.00%	[4]

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

[2] The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period (the "CEU Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

[3] The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 3 "Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

[4] The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 3 "Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. During the three months ended September 30, 2014, a purchase price allocation adjustment was made for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

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Goodwill and Intangible Assets - Schedule of Goodwill (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014		Jun. 26, 2014
Goodwill [Roll Forward]
Goodwill at December 31, 2013		$ 23,974
Change due to purchase price allocation adjustments	3,800	3,836	[1]
Goodwill at September 30, 2014	43,534	43,534
EFS and RPS
Goodwill [Roll Forward]
Goodwill at December 31, 2013				15,397	[2],[3]
Additions		11,664
Change due to purchase price allocation adjustments	3,700
Goodwill at September 30, 2014				15,397	[2],[3]
MCCS
Goodwill [Roll Forward]
Goodwill at December 31, 2013				4,060	[4]
Additions		4,060
Goodwill at September 30, 2014				$ 4,060	[4]

[1] Includes adjustments totaling $3.8 million during the three months ended September 30, 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. See Note 2 "Acquisitions" for discussion of the purchase price allocation adjustments.

[2] Includes purchase price allocation adjustments, resulting in an increase totaling $3.7 million to goodwill, during the three months ended September 30, 2014, based on additional information received primarily on other current assets and property and equipment acquired.

[3] Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the 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. During the three months ended, a purchase price allocation adjustment was made to increase the amount assigned to goodwill by approximately $3.7 million, primarily as a result of an increase to the value of the contingent consideration based on additional information made available.

[4] Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS's business. Goodwill has been allocated to the oilfield services segment.

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Condensed Consolidated Balance Sheets (Unaudited) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash	$ 5,696	$ 7,291
Restricted cash	25	0
Accounts receivable	40,492	12,609
Other current assets	7,867	1,114
Total current assets	54,080	21,014
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	329,864	291,829
Less: Accumulated depreciation, depletion, and amortization	(148,427)	(128,961)
Total oil and natural gas properties, net	181,437	162,868
Property and equipment, net	63,281	8,166
Intangible assets, net	89,813	35,009
Goodwill	43,534	23,974
Other assets	2,379	3,679
Total assets	434,524	254,710
Current liabilities:
Accounts payable and accrued liabilities	12,636	3,267
Accounts payable-related parties	5,103	8,221
Factoring payable	15,526	1,907
Contingent consideration payable	36,854	0
Derivative contracts	608	3,167
Current portion of long-term debt	21,132	719
Total current liabilities	91,859	17,281
Long-term debt	96,301	80,014
Contingent consideration payable to related parties	0	6,320
Asset retirement obligations	3,877	3,455
Other liabilities	396	387
Total liabilities	192,433	107,457
Commitments and contingencies (Note 14)
Unitholders' equity:
Common units (15,440,381 units issued and outstanding at September 30, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	257,876	151,773
Common units held in escrow	(8,227)	0
Subordinated units (2,205,000 units issued and outstanding at September 30, 2014 and December 31, 2013)	(21,582)	(17,334)
General partner's units (155,102 units issued and outstanding at September 30, 2014 and December 31, 2013)	(1,473)	(1,174)
Total New Source Energy Partners L.P. unitholders' equity	226,594	133,265
Noncontrolling interest	15,497	13,988
Total unitholders' equity	242,091	147,253
Total liabilities and unitholders' equity	$ 434,524	$ 254,710

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Acquisitions - Summary of Assets Acquired and Liabilities Assumed in MCE Acquisition (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Nov. 30, 2013 MidCentral Energy Services		Nov. 30, 2013 Customer Relationships MidCentral Energy Services
Business Acquisition [Line Items]
Cash			$ 1,522
Accounts receivable			3,365
Other current assets			954
Property and equipment			7,923
Intangible Asset					36,772	[1]
Goodwill	43,534	23,974	24,077	[2]
Other assets			19
Total assets acquired			74,632
Accounts payable and accrued liabilities			(2,448)	[3]
Factoring payable			(1,679)
Long-term debt			(2,335)
Total liabilities assumed			(6,462)
Total net assets			$ 68,170

[1] Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

[2] Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.

[3] Includes purchase price allocation adjustment of $0.1 million made during the three months ended September 30, 2014 based on additional information received on accounts payable assumed.

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Condensed Consolidated Statements of Cash Flow (Unaudited) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013
Cash Flows from Operating Activities:
Net (loss) income	$ (2,701)		$ 4,768
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	37,329		11,686
Accretion	219		145
Amortization of deferred loan costs	451		358
Write off of loan costs due to debt refinancing	0		1,436
Equity-based compensation	1,906		7,738
Deferred income tax benefit	0		(12,023)
Change in fair value of contingent consideration	4,493		0
Gain on investment in acquired business	(2,298)		0
Loss on derivative contracts, net	760	[1]	2,597	[1]
Cash paid on settlement of derivative contracts	(3,750)		(878)
Payments for premiums on derivatives	0		(1,334)
Changes in operating assets and liabilities:
Accounts receivable	(4,533)		(9,673)
Other current assets and other assets	(3,582)		(160)
Accounts payable and accrued liabilities	(1,893)		5,020
Net cash provided by operating activities	26,401		9,680
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	(63,446)		(15,957)
Additions to oil and natural gas properties	(20,845)		(18,261)
Additions to other property and equipment	(6,726)		0
Net cash used in investing activities	(91,017)		(34,218)
Cash Flows from Financing Activities:
Proceeds from borrowings	22,544		69,500
Payments on borrowings	(8,401)		(95,000)
Bank overdraft	281		0
Proceeds from financing	527		0
Proceeds from borrowings, net - related party	300		0
Payments for deferred loan costs	(437)		(1,762)
Payments on factoring payable, net	(2,221)		0
Proceeds from sales of common units, net of offering costs	76,191		77,880
Payments of offering costs	(100)		0
Distribution to unitholders	(25,663)		(7,527)
Distribution to NSEC	0		(18,295)
Net cash provided by financing activities	63,021		24,796
Net change in cash and cash equivalents	(1,595)		258
Cash and cash equivalents, beginning of period	7,291		0
Cash and cash equivalents, end of period	5,696		258
Supplemental Cash Flow Information:
Cash paid for interest	2,999		1,476
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation	203		1,403
Decrease in accrued capital expenditures	(1,561)		(258)
Accounts receivable distributed to NSEC	0		(7,014)
Accounts payable assumed by NSEC	0		(1,742)
Subordinated note issued to NSEC for oil and natural gas properties	0		25,000
Common units issued in connection with acquisitions	(45,447)
Acquisition of property and equipment by financing	6,707		0
Factoring payables assumed in connection with acquisitions	15,840		0
Debt assumed in connection with acquisitions	17,571		0
2014 Acquisitions
Non-cash Investing and Financing Activities:
Common units issued in connection with acquisitions	(46,239)		(27,983)
Noncontrolling Interest
Cash Flows from Operating Activities:
Net (loss) income	242
Non-cash Investing and Financing Activities:
Distributions payable	242		0
Common units issued in connection with acquisitions	$ (1,509)

[1] Included in gain (loss) on derivative contracts for the three months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $0.3 million and $0.5 million, respectively. Included in loss on derivative contracts for the nine months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $3.8 million and $0.9 million, respectively.

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Derivative Contracts - Commodity Derivative Positions Natural Gas Collars (Details) (Natural Gas Collars)	9 Months Ended
	Sep. 30, 2014 MMBTU
2014
Derivative [Line Items]
Volumes (MMBtu)	260,751
Floor Price (in usd per MMBtu)	4
Ceiling Price (in usd per MMBtu)	4.41
2015
Derivative [Line Items]
Volumes (MMBtu)	1,362,382
Floor Price (in usd per MMBtu)	4
Ceiling Price (in usd per MMBtu)	4.32

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Business Segment Information (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands):

	Exploration and Production			Oilfield Services (1)			Total
Three Months Ended September 30, 2014
Revenues	$	15,561		$	40,863		$	56,424
Direct operating expenses	5,562			24,315			29,877
Segment margin	$	9,999		$	16,548		$	26,547
General and administrative expenses	7,354			6,431			13,785
Depreciation, depletion, amortization and accretion	6,834			11,003			17,837
Loss from operations	$	(4,189	)	$	(886	)	$	(5,075	)
Capital expenditures (2)	$	824		$	3,735		$	4,559
Three Months Ended September 30, 2013
Revenues	$	12,431		$	—		$	12,431
Direct operating expenses	3,985			—			3,985
Segment margin	$	8,446		$	—		$	8,446
General and administrative expenses	1,353			—			1,353
Depreciation, depletion, amortization and accretion	4,972			—			4,972
Income from operations	$	2,121		$	—		$	2,121
Capital expenditures (2)	$	14,745		$	—		$	14,745

__________

(1) The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion.

(2) On an accrual basis and exclusive of acquisitions.

	Exploration and Production			Oilfield Services (1)			Total
Nine Months Ended September 30, 2014
Revenues	$	51,130		$	59,539		$	110,669
Direct operating expenses	16,252			34,849			51,101
Segment margin	$	34,878		$	24,690		$	59,568
General and administrative expenses	13,220			9,615			22,835
Depreciation, depletion, amortization and accretion	19,692			17,856			37,548
Income (loss) from operations	$	1,966		$	(2,781	)	$	(815	)
Capital expenditures (2)	$	19,284		$	6,726		$	26,010
At September 30, 2014
Total assets	$	194,541		$	239,983		$	434,524
Nine Months Ended September 30, 2013
Revenues	$	32,440		$	—		$	32,440
Direct operating expenses	10,698			—			10,698
Segment margin	$	21,742		$	—		$	21,742
General and administrative expenses (3)	11,452			—			11,452
Depreciation, depletion, amortization and accretion	11,831			—			11,831
Loss from operations	$	(1,541	)	$	—		$	(1,541	)
Capital expenditures (2)	$	18,261		$	—		$	18,261
At December 31, 2013
Total assets	$	181,440		$	73,270		$	254,710

__________

(1) The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion.

(2) On an accrual basis and exclusive of acquisitions.

(3) Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

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Derivative Contracts - Commodity Derivative Positions Liquid Swaps (Details) (Natural Gas Liquid Swaps)	9 Months Ended
	Sep. 30, 2014 bbl
2014
Derivative [Line Items]
Volumes (Bbls)	168,924
Derivative, Swap Type, Average Fixed Price	39.44
2015
Derivative [Line Items]
Volumes (Bbls)	84,793
Derivative, Swap Type, Average Fixed Price	75.18

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Subsequent Events

9 Months Ended

Sep. 30, 2014

Subsequent Events [Abstract]

Subsequent Events

Subsequent Events

Equity Offering. On October 3, 2014, the Partnership and our general partner entered into an Equity Distribution Agreement (the “Agreement”) with BMO Capital Markets Corp. (the “Sales Agent”). Pursuant to the terms of the Agreement, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. Sales of such common units, if any, will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange at market prices, or as otherwise agreed by the Partnership and the Sales Agent. On October 6, 2014, the Partnership sold 720,000 common units under the Agreement for net proceeds of approximately $16.4 million. Proceeds will be used to pay down a portion of the Partnership's credit facility and for general corporate purposes.

Distributions.On October 21, 2014, the Partnership declared quarterly distributions of $0.585 per unit to unitholders of record, including holders of common, subordinated and general partner units for the three months ended September 30, 2014. The following distributions will be paid on November 14, 2014 to holders of record as of the close of business on November 3, 2014 (in thousands):

	Common Units		Subordinated Units		General Partner Units		Total
Distributions	$	9,454	$	1,290	$	91	$	10,835

Lease. On October 27, 2014, MCE entered into a master lease agreement whereby it can enter into capital leases for certain property and equipment totaling up to $25 million. The master lease agreement does not obligate MCE to enter into any such leases, and no amounts are currently outstanding under this master lease agreement.

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Subsequent Events (Tables)

9 Months Ended

Sep. 30, 2014

Subsequent Events [Abstract]

Schedule of Distributions Made to Units

The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common, subordinated and general partner units during the three and nine months ended September 30, 2014 and 2013, as shown in the following table (in thousands):

Distributions	Common Units		Subordinated Units		General Partner Units		Total
2014
First Quarter (1)	$	4,681	$	1,268	$	89	$	6,038
Second Quarter (2)	$	7,852	$	1,279	$	90	$	9,221
Third Quarter (3)	$	9,025	$	1,290	$	91	$	10,406
2013
Second Quarter (4)	$	1,857	$	604	$	43	$	2,504
Third Quarter (1)	$	3,895	$	1,268	$	89	$	5,252

__________

(1)    Reflects quarterly distributions of $0.575 per unit paid in the third quarter of 2013 and the first quarter of 2014.

(2)    Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014.

(3)    Reflects quarterly distributions of $0.585 per unit paid in the third quarter of 2014.

(4)    Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.

The following distributions will be paid on November 14, 2014 to holders of record as of the close of business on November 3, 2014 (in thousands):

	Common Units		Subordinated Units		General Partner Units		Total
Distributions	$	9,454	$	1,290	$	91	$	10,835

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Acquisitions (Tables)

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Schedule of Business Acquisitions, by Acquisition

Total consideration for the MCE Acquisition is as follows (in thousands):

Consideration:
Cash	$	3,781
Fair value of common units granted (1)	41,822
Common units granted to MCE employees (2)	2,259
Contingent consideration (3)	6,320
MCE Class B units granted (4)	13,988
Total fair value of consideration	$	68,170

__________

(1) The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).

(2) The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnership’s long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.

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

(4) Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See Note 9 "Equity" for additional discussion of these incentive distributions. The Class B units were valued at $14.0 million at the acquisition date through the use of a Monte Carlo simulation.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition, net of purchase price adjustments, is as follows (in thousands):

Consideration:
Cash	$	5,503
Fair value of common units granted (1)	11,621
Contingent consideration (2)	—
Total fair value of consideration	$	17,124
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	17,306
Asset retirement obligations	(182		)
Total net assets	$	17,124

__________

(1) The fair value of the unit consideration was based upon 488,667 common units valued at $23.78 per unit (closing price on the date of the acquisition).

(2) The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period (the "CEU Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	8,165
Asset retirement obligations	(19		)
Other liabilities	(254		)
Total net assets	$	7,892

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	3,274
Asset retirement obligations	(24		)
Other liabilities	(20		)
Total net assets	$	3,230

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	109
Accounts receivable	524
Inventory	2,035
Other current assets	14
Property and equipment	107
Intangible asset (1)	1,700
Goodwill (2)	4,060
Other assets	28
Total assets acquired	8,577
Accounts payable and accrued liabilities	(1,431		)
Long-term debt	(791		)
Total liabilities assumed	(2,222		)
Net assets acquired	$	6,355

__________

(1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

(2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS's business. Goodwill has been allocated to the oilfield services segment.

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 and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition are excluded from consideration based on the future service requirement for vesting. See Note 9 "Equity" for additional discussion of phantom units.

(3) The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 3 "Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. During the three months ended September 30, 2014, a purchase price allocation adjustment was made for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	1,668
Accounts receivable	21,611
Other current assets (1)	620
Property and equipment (1)	43,853
Intangible assets (2)	68,700
Goodwill (1) (3)	15,397
Total assets acquired	151,849
Accounts payable and accrued liabilities (1)	(6,047		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,687		)
Net assets acquired	$	113,162

__________

(1) Includes purchase price allocation adjustments, resulting in an increase totaling $3.7 million to goodwill, during the three months ended September 30, 2014, based on additional information received primarily on other current assets and property and equipment acquired.

(2) 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.

(3) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the 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. During the three months ended, a purchase price allocation adjustment was made to increase the amount assigned to goodwill by approximately $3.7 million, primarily as a result of an increase to the value of the contingent consideration based on additional information made available.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	29,049
Other assets	754
Asset retirement obligations	(1,333		)
Other liabilities	(488		)
Total net assets	$	27,982

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)	1,509
Total fair value of consideration	$	6,355

__________

(1) The fair value of the unit consideration was based upon 33,646 common units valued at $23.45 per unit (closing price on the date of the acquisition).

(2) The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 3 "Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

(3) As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	4,888
Asset retirement obligations	(4		)
Other liabilities	(18		)
Total net assets	$	4,866

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Consideration:
Cash	$	4,260
Fair value of common units granted (1)	8,608
Contingent consideration (2)	1,600
Total fair value of consideration	$	14,468
Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	15,190
Asset retirement obligations	(170		)
Other liabilities	(552		)
Total net assets	$	14,468

__________

(1) The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).

(2) The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See Note 3 "Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideration.

The total purchase price allocated to the assets acquired and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	1,522
Accounts receivable	3,365
Other current assets	954
Property and equipment	7,923
Intangible asset (1)	36,772
Goodwill (2) (3)	24,077
Other assets	19
Total assets acquired	74,632
Accounts payable and accrued liabilities (3)	(2,448		)
Factoring payable	(1,679		)
Long-term debt	(2,335		)
Total liabilities assumed	(6,462		)
Net assets acquired	$	68,170

__________

(1) Customer relationships, an identifiable intangible asset, were valued based on the estimated free cash flows the customer relationships are expected to provide and are amortized using an accelerated method over seven years.

(2) Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.

(3) Includes purchase price allocation adjustment of $0.1 million made during the three months ended September 30, 2014 based on additional information received on accounts payable assumed.

Summary of Operating Results

	Three Months Ended September 30, 2013		Nine Months Ended September 30, 2013
	(in thousands)
Revenue	$	4,197	$	6,974
Excess of revenues over direct operating expenses	$	2,180	$	3,350

	Three Months Ended September 30, 2014		Nine Months Ended September 30, 2014
	(in thousands)
Revenue	$	30,110	$	35,047
Operating income	$	590	$	2,786

Business Acquisition, Pro Forma Information

	Three Months Ended September 30, 2013			Nine Months Ended September 30, 2013
	(in thousands, except per unit amounts)
Revenue	$	65,673		$	136,851
Net loss attributable to New Source Energy Partners L.P. (1)	$	(3,971	)	$	(10,647	)
Net loss per common unit (1):
Basic	$	(0.24	)	$	(0.83	)
Diluted	$	(0.24	)	$	(0.83	)

__________

(1)    Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the nine months ended September 30, 2013.

	Nine Months Ended September 30, 2014
	(in thousands, except per unit amounts)
Revenue	$	172,590
Net income attributable to New Source Energy Partners L.P. (1)	$	5,084
Net income per common unit (1):
Basic	$	0.31
Diluted	$	0.31

__________

(1) Excludes $24.3 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.

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Derivative Contracts (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash paid on settlement of derivative contracts	$ (338)	$ (500)	$ (3,750)	$ (878)

XML

Basis of Presentation

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

Nature of Business.  We are a vertically integrated independent energy partnership formed in October 2012. The Partnership is engaged in the development and 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, the Partnership is engaged in oilfield services through its oilfield services subsidiaries. Our oilfield services business provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, throughout the Mid-Continent region and in South Texas and West Texas. In June 2014, we acquired oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry primarily in Oklahoma, Texas, Pennsylvania and Ohio.

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, 2013 have been derived from the audited financial statements contained in the Partnership’s 2013 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2013 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s 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 2013 Form 10-K.

Significant Accounting Policies. For a description of the Partnership’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2013 Form 10-K.

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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed and asset retirement obligations. Actual results could differ from those estimates.

Recently Issued Accounting Standard. In May 2014, the Financial Accounting Standards Board 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. ASU 2014-09 is effective for fiscal years beginning after December 15, 2016 and is to be applied retrospectively. Early application is not permitted. We are in the process of assessing the potential impact of ASU 2014-09 on the Partnership's financial statements.

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Condensed Consolidated Balance Sheets (Unaudited) (Parentheticals)	Sep. 30, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Common units outstanding (in Shares)	15,440,381	9,599,578
Common units issued (in Shares)	15,440,381	9,599,578
Subordinated units outstanding (in Shares)	2,205,000	2,205,000
Subordinated units issued (in Shares)	2,205,000	2,205,000
General partner's capital units outstanding (in Shares)	155,102	155,102
General partner's capital units, issued (in Shares)	155,102	155,102

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Related Party Transactions

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Ownership. The Partnership is controlled by the Partnership's general partner, which is owned 69.4% by Kristian Kos, the President and Chief Executive Officer of our general partner, and 25.0% by David J. Chernicky, the former Chairman of the board of directors of our general partner. Mr. Kos beneficially owns approximately 5.3% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through Deylau, LLC, an entity he controls. As of September 30, 2014, Mr. Chernicky beneficially owned approximately 17.2% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through NSEC and Scintilla, entities that he controls. In addition, Mr. Chernicky beneficially owns 100% of the 2,205,000 subordinated units through his control of NSEC. As a result of Mr. Chernicky's ownership of the Partnership and his ownership of all of the membership interests in New Dominion, which operates all of the Partnership's oil and natural gas properties, transactions with New Dominion are deemed to be with a related party.

New Dominion. New Dominion is an exploration and production operator, which is wholly owned by Mr. Chernicky. Pursuant to various development agreements with the Partnership, New Dominion is currently contracted to operate the Partnership’s existing wells. New Dominion has historically performed this service for NSEC. In addition to the various development agreements, the Partnership, along with other working interest owners, is a party to an agreement with New Dominion in which we reimburse New Dominion for our proportionate share of costs incurred to construct a gas gathering system. In return, we own a portion of such gas gathering system, which facilitates the transportation of our production in the Greater Golden Lane field to the gas processing plant.

New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated was approximately $0.4 million as of both September 30, 2014 and December 31, 2013, all of which is classified as a long-term liability in the accompanying unaudited condensed consolidated balance sheets. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.

Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Producing overhead and supervision charges	$	624	$	464	$	2,080	$	1,277
Drilling and completion supervision charges	60		119		230		246
Saltwater disposal fees	260		329		1,075		502
Total expenses incurred	$	944	$	912	$	3,385	$	2,025

At September 30, 2014 and December 31, 2013, $2.2 million and $1.3 million, respectively, were due to New Dominion for charges and fees under operating agreements and included in accounts payable - related party in the accompanying unaudited condensed consolidated balance sheets.

NSEC. Under an agreement by and among NSEC, the Partnership and our general partner, NSEC provided administrative services for the Partnership from February 13, 2013 through December 31, 2013. For the three and nine months ended September 30, 2013, fees paid for such services were $0.7 million and $1.8 million, respectively, and were included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations.

New Source Energy GP, LLC. Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three and nine months ended September 30, 2014, amounts paid to our general partner for such reimbursements were $0.5 million and $1.1 million, respectively, and were included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations. Additionally, we received approximately $1.5 million and paid approximately $1.2 million to our general partner during the nine months ended September 30, 2014 for operational cash advances. At September 30, 2014 and December 31, 2013, $0.8 million and $0.4 million, respectively, were due to our general partner for reimbursement and included in accounts payable - related party in the accompanying unaudited condensed consolidated balance sheets.

Acquisitions. As described in Note 2 "Acquisitions," we acquired oil and natural gas properties, MCE and MCCS from related parties. As these acquisitions were with related parties, the transactions were subject to approval by the board of directors of the Partnership's general partner, based on the approval and recommendation of its conflicts committee.

As discussed in Note 2 "Acquisitions," Mr. Kos was a 36% owner of MCE prior to the MCE Acquisition. Additionally, Dikran Tourian, President-Oilfield Services Division and member of our general partner's board of directors, was a 36% owner of MCE prior to the MCE Acquisition. In conjunction with the MCE Acquisition, Mr. Kos and Mr. Tourian retained Class B units that are entitled to incentive distributions as discussed in Note 9 "Equity" as well as contingent consideration as discussed in Note 3 "Contingent Consideration." In the third quarter of 2014, the Class B unit distribution targets were met. Distributions of $0.2 million for the Class B unitholders are reflected in accounts payable - related parties in the accompanying unaudited consolidated balance sheet at September 30, 2014.

On June 26, 2014, we exercised our option to acquire MCCS, which was owned by Mr. Kos and Mr. Tourian. See Note 2 "Acquisitions" for discussion of this acquisition and Note 3 "Contingent Consideration" for discussion of the MCCS Contingent Consideration. As part of the acquisition of MCCS, we assumed a payable to an entity owned by Mr. Kos and Mr. Tourian. As of September 30, 2014, $0.7 million was remaining and reflected in accounts payable - related parties in the accompanying unaudited consolidated balance sheet.

Transactions with Chief Financial Officer. The Partnership engaged Finley & Cook, PLLC ("Finley & Cook") to provide various accounting services on our behalf during the nine months ended September 30, 2014. Richard Finley, the Chief Financial Officer of our general partner, is an equity member of Finley & Cook, holding a 31.5% ownership interest. The Partnership paid Finley & Cook approximately $0.06 million and $0.4 million in fees for the three and nine months ended September 30, 2014 respectively. NSEC engaged Finley & Cook to provide various accounting services on our behalf during the year ended December 31, 2013. Fees for such accounting services were included in the amounts paid to NSEC, as discussed above.

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Document And Entity Information	9 Months Ended
	Sep. 30, 2014	Nov. 03, 2014 Common Units	Nov. 03, 2014 Subordinated Units	Nov. 03, 2014 General Partnership Units
Document Information [Line Items]
Entity Registrant Name	New Source Energy Partners L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		16,160,381	2,205,000	155,102
Amendment Flag	false
Entity Central Index Key	0001560443
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3

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Property, Plant and Equipment

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

Oil and Natural Gas Properties. We use the full cost method to account for our oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil 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.

Property and equipment, net.Property and equipment, primarily for our oilfield services segment, consisted of the following (in thousands):

	September 30, 2014			December 31, 2013
Vehicles and transportation equipment	$	15,317		$	561
Machinery and equipment	38,746			4,757
Office furniture and equipment	472			79
Iron	11,212			2,971
Total	65,747			8,368
Less: accumulated depreciation	(2,466		)	(202		)
Property and equipment, net	$	63,281		$	8,166

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Related Party Transactions - Summary of Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Related Party Transaction [Line Items]
Related Party Costs	$ 944	$ 912	$ 3,385	$ 2,025
Producing Overhead Charges | New Dominion LLC
Related Party Transaction [Line Items]
Related Party Costs	624	464	2,080	1,277
Drilling And Completion Overhead Charges | New Dominion LLC
Related Party Transaction [Line Items]
Related Party Costs	60	119	230	246
Saltwater Disposal Fees | New Dominion LLC
Related Party Transaction [Line Items]
Related Party Costs	$ 260	$ 329	$ 1,075	$ 502

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Condensed Statements of Operations (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Revenues:
Oil sales	$ 3,798		$ 2,044		$ 12,146		$ 4,879
Natural gas sales	3,711		2,582		12,928		7,031
NGL sales	8,052		7,805		26,056		20,530
Oilfield services	40,863		0		59,539		0
Total revenues	56,424		12,431		110,669		32,440
Operating costs and expenses:
Oil, natural gas and NGL production	4,894		3,428		13,913		8,702
Production taxes	668		557		2,339		1,996
Cost of providing oilfield services	24,315		0		34,849		0
Depreciation, depletion and amortization	17,760		4,913		37,329		11,686
Accretion	77		59		219		145
General and administrative	13,785		1,353		22,835		11,452	[1]
Total operating costs and expenses	61,499		10,310		111,484		33,981
Operating (loss) income	(5,075)		2,121		(815)		(1,541)
Other income (expense):
Interest expense	(1,458)		(654)		(3,442)		(3,220)
Gain (loss) on derivative contracts, net	3,768	[2]	(3,453)	[2]	(760)	[2]	(2,597)	[2]
Gain on investment in acquired business	0		0		2,298		0
Other income	11		0		18		0
Loss before income taxes	(2,754)		(1,986)		(2,701)		(7,358)
Income tax benefit	0		0		0		12,126
Net (loss) income	(2,754)		(1,986)		(2,701)		4,768
Less: net income attributable to noncontrolling interest	242		0		242		0
Net (loss) income	(2,996)		(1,986)		(2,943)		4,768
General Partnership Units
Other income (expense):
Net (loss) income					(29)
Net loss per unit:
Basic and diluted income per unit (in usd per unit)	$ (0.17)		$ (0.22)		$ (0.19)		$ (0.19)
Subordinated Units
Other income (expense):
Net (loss) income					(411)
Net loss per unit:
Basic and diluted income per unit (in usd per unit)	$ (0.17)		$ (0.22)		$ (0.19)		$ (0.20)
Common Units
Other income (expense):
Net (loss) income					$ (2,503)
Net loss per unit:
Basic and diluted income per unit (in usd per unit)	$ (0.17)		$ (0.22)		$ (0.20)		$ (0.01)

[1] Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

[2] Included in gain (loss) on derivative contracts for the three months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $0.3 million and $0.5 million, respectively. Included in loss on derivative contracts for the nine months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $3.8 million and $0.9 million, respectively.

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Derivative Contracts

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Contracts

Derivative Contracts 

Due to the volatility of commodity prices, the Partnership periodically enters into derivative contracts to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations for a portion of its oil, natural gas and NGL production. While the use of derivative contracts limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and 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 September 30, 2014, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.
Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.
Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the put option and the fixed price.
Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The following tables present our derivative instruments outstanding as of September 30, 2014:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2014	23,763	$	80.00	$	103.50
2015	42,649	$	80.00	$	93.25

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	36,500	$	77.50	$	92.50	$	102.60

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2014	260,751	$	4.00	$	4.41
2015	1,362,382	$	4.00	$	4.32

Oil put options	Volumes (Bbls)	Floor Price
2014	7,418	$	80.00

Natural gas put options	Volumes (MMBtu)	Floor Price
2014	99,034	$	3.50
2015	798,853	$	3.50
2016	930,468	$	3.50

NGL put options	Volumes (Bbls)	Average Floor Price
2014	5,535	$	63.19

Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	6,900	$	103.52
2015	39,411	$	88.90
2016	36,658	$	86.00

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2014	176,795	$	4.09
2015	800,573	$	4.25
2016	629,301	$	4.37

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	168,924	$	39.44
2015	84,793	$	75.18

By using derivative instruments to mitigate exposures to changes in commodity prices, the Partnership exposes itself to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. The Partnership nets derivative assets and liabilities for counterparties where it has a legal right of offset. Such credit risk is mitigated by the fact that the Partnership's derivatives counterparties are major financial institutions with investment grade credit ratings, some of which are lenders under the Partnership's credit facility.  In addition, the Partnership routinely monitors the creditworthiness of its counterparties.

The following table summarizes our derivative contracts on a gross basis, the effects of netting assets and liabilities for which the right of offset exists (in thousands):

September 30, 2014	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,065	$	(404	)	$	661
Commodity derivatives - long-term assets	565		(6		)	559
Total	$	1,630	$	(410	)	$	1,220
Liabilities:
Commodity derivatives - current liabilities	$	1,012	$	(404	)	$	608
Commodity derivatives - long-term liabilities	43		(6		)	37
Total	$	1,055	$	(410	)	$	645

December 31, 2013	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,342	$	(1,212	)	$	130
Commodity derivatives - long-term assets	1,638		(978		)	660
Total	$	2,980	$	(2,190	)	$	790
Liabilities:
Commodity derivatives - current liabilities	$	4,379	$	(1,212	)	$	3,167
Commodity derivatives - long-term liabilities	1,015		(978		)	37
Total	$	5,394	$	(2,190	)	$	3,204

See Note 7 "Fair Value Measurements" for additional information on the fair value measurement of the Partnership's derivative contracts.

The following table presents gain (loss) on our derivative contracts as included in the accompanying unaudited statements of operations for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Total gain (loss) on derivative contracts, net (1)	$	3,768	$	(3,453	)	$	(760	)	$	(2,597	)

__________

(1) Included in gain (loss) on derivative contracts for the three months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $0.3 million and $0.5 million, respectively. Included in loss on derivative contracts for the nine months ended September 30, 2014 and 2013 are net cash payments upon contract settlement of $3.8 million and $0.9 million, respectively.

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Factoring Payable

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Factoring Payable

Factoring Payable

The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of MCES. At December 31, 2013, the outstanding balance was $1.9 million. The outstanding balance was paid and the agreement was terminated in February 2014 when MCES established its line of credit. See Note 4 "Debt" for discussion of MCES' line of credit.

In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 3% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not collected within 90 days, the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $15.5 million as of September 30, 2014.

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Interim Financial Statements

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2013 have been derived from the audited financial statements contained in the Partnership’s 2013 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2013 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s 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 2013 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 GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed and asset retirement obligations. Actual results could differ from those estimates.

Recently Issued Accounting Standard

Recently Issued Accounting Standard. In May 2014, the Financial Accounting Standards Board 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. ASU 2014-09 is effective for fiscal years beginning after December 15, 2016 and is to be applied retrospectively. Early application is not permitted. We are in the process of assessing the potential impact of ASU 2014-09 on the Partnership's financial statements.

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.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligations

A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2013 to September 30, 2014 is as follows (in thousands):

Asset retirement obligation at December 31, 2013	$	3,455
Liability incurred upon acquiring and drilling wells	235
Liability settled or disposed	(32		)
Accretion	219
Asset retirement obligation at September 30, 2014	$	3,877

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Business Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 segment	Sep. 30, 2013
Segment Reporting Information [Line Items]
Number of operating segments			2
Equity-based compensation	$ 1,300	$ 0	$ 1,906	$ 7,738
Exploration and Production | General and Administrative Expenses
Segment Reporting Information [Line Items]
Equity-based compensation			$ 7,700

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Equity

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Equity

Equity

Common Units

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, respectively. See Note 2 "Acquisitions" for additional discussion of these transactions.

Equity Offering. On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million. We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes.

Distributions

Distributions are declared and distributed within 45 days following the end of each quarter. The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common, subordinated and general partner units during the three and nine months ended September 30, 2014 and 2013, as shown in the following table (in thousands):

Distributions	Common Units		Subordinated Units		General Partner Units		Total
2014
First Quarter (1)	$	4,681	$	1,268	$	89	$	6,038
Second Quarter (2)	$	7,852	$	1,279	$	90	$	9,221
Third Quarter (3)	$	9,025	$	1,290	$	91	$	10,406
2013
Second Quarter (4)	$	1,857	$	604	$	43	$	2,504
Third Quarter (1)	$	3,895	$	1,268	$	89	$	5,252

__________

(1)    Reflects quarterly distributions of $0.575 per unit paid in the third quarter of 2013 and the first quarter of 2014.

(2)    Reflects quarterly distributions of $0.58 per unit paid in the second quarter of 2014.

(3)    Reflects quarterly distributions of $0.585 per unit paid in the third quarter of 2014.

(4)    Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit paid in the second quarter of 2013.

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, second or third quarters of 2014 and 2013 did not exceed the specified targets.

See Note 16 "Subsequent Events" for discussion of distribution declared in October 2014.

Noncontrolling Interest

As part of the MCE Acquisition, certain former owners of MCE retained 100 Class B Units in MCE. The MCE partnership agreement provides that the Class B Units have the right to receive an increasing percentage (15%, 25% and 50%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved based on results of MCES and MCCS. Target distribution levels are adjusted, as applicable and in accordance with the MCE partnership agreement, under certain circumstances. As these Class B Units are not held by the Partnership, they are presented as noncontrolling interest in the accompanying unaudited condensed consolidated financial statements. Any distribution to the Class B Units will be recognized in the period earned and recorded as a reduction to net income attributable to the Partnership.

As a result of the MCCS Acquisition, the specified target distribution levels for the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders were adjusted for the contribution of MCCS to MCE by the Partnership as provided for in the MCE partnership agreement. The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels, as adjusted based on the MCCS Acquisition.

				Marginal Percentage Interest in  Distributions
	Total Quarterly Distributions per MCE Unit			MCE Class A Unitholders (the Partnership)	MCE Class B Unitholders
Minimum Quarterly Distribution	$16,116			100%	—%
First Target Distribution	$18,533	to	$20,144	85%	15%
Second Target Distribution	$20,145	to	$24,173	75%	25%
Third Target Distribution and Thereafter	$24,174	and above		50%	50%

Based on MCE's distribution amounts, the MCE Class B unitholders were entitled to distributions of approximately $0.2 million for the three months ended September 30, 2014. No distributions were due to the MCE Class B unitholders for the first or second quarter of 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"). Such awards are valued based upon the market value of common units on the date of grant and expensed over the relevant vesting period to the extent the awards contain a service requirement. If there is no service requirement, the awards are expensed at the time of grant. For the three and nine months ended September 30, 2014, the Partnership recorded equity-based compensation expense of $1.3 million and $1.9 million, respectively. For the nine months ended September 30, 2013, the Partnership recorded equity-based compensation expense of $7.7 million. Additionally, the Partnership had $0.4 million of allocated equity-based compensation from NSEC during the nine months ended September 30, 2013. There was no equity-based compensation expense for the three months ended September 30, 2013.

Phantom Units. In conjunction with the Services Acquisition, the Partnership granted 432,038 phantom units, which represent the right to receive common units or cash equal to the value of the associated common units, to employees of EFS and RPS under the FMVPP. The phantom units vest over a period not to exceed 2 years. If a phantom unit is forfeited, the associated common units are released from escrow to an entity owned by the former owners of EFS and RPS. Except as otherwise provided in the Phantom Unit Agreement, phantom units subject to forfeiture restrictions may be forfeited upon termination of employment prior to the end of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the holder until the phantom units vest, the recipients have distribution equivalent rights on these phantom units from the date of grant.

Although the phantom unit grants may be settled in either common units or cash at the holder's election, the settlement of the phantom units upon vesting will be made from a transfer or sale of the associated common units that were issued to an escrow account in conjunction with the Services Acquisition. As a result, the 401,171 phantom units valued at $9.4 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. At September 30, 2014, approximately $8.2 million remains to be expensed. The associated common units held in escrow are reflected as contra equity on the accompanying unaudited condensed consolidated balance sheet at September 30, 2014.

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Derivative Contracts - Commodity Derivative Positions Oil Options (Details) (Oil Options, 2014)	9 Months Ended
	Sep. 30, 2014 bbl
Oil Options | 2014
Derivative [Line Items]
Volumes (Bbls)	7,418
Floor Price (in usd per Bbl)	80

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

We measure and report certain assets and liabilities at fair value and classify and disclose our fair value measurements based on the levels of the fair value hierarchy, as described below:

Level 1:     Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2:     Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3:     Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership's assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Level 2 Fair Value Measurements

Derivative contracts. The fair values of our commodity collars, put options and fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. The Partnership estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. The Partnership validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. The Partnership estimates the option value of puts and calls combined into hedges, market prices, contract parameters and discount rates based on published LIBOR rates.

Level 3 Fair Value Measurements

Derivative contracts. The fair values of our natural gas collars, natural gas and NGL put options and NGL fixed price swaps at December 31, 2013 were based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness. The significant unobservable inputs used in the fair value measurement of our natural gas and NGL put options and NGL fixed price swaps were the estimated probability of exercise and the estimate of NGL futures prices. Significant increases (decreases) in the probability of exercise and NGL futures prices could result in a significantly higher (lower) fair value measurement. 

Contingent consideration. As discussed in Note 3 "Contingent Consideration," the Partnership has agreed to pay additional consideration on the MCE Acquisition, the MCCS Acquisition and the Services Acquisition. The fair value of the contingent consideration resulting from these acquisitions is based on the present value of estimated future payments, using various inputs, including forecasted EBITDA metrics and the probability that targets for additional payout will be met. Significant increases (decreases) in the probability of meeting target payout levels could result in a significantly higher (lower) fair value measurement. 

The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis (in thousands):

September 30, 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	$	—	$	157		$	—		$	157
Oil, natural gas and NGL put options	—		539			—			539
Oil, natural gas and NGL fixed price swaps	—		(121		)	—			(121		)
Contingent consideration	—		—			(36,854		)	(36,854		)
Total	$	—	$	575		$	(36,854	)	$	(36,279	)

December 31, 2013	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
Oil collars	$	—	$	(57	)	$	—		$	(57	)
Natural gas collars	—		—			(9		)	(9		)
Oil put options	—		28			—			28
Natural gas and NGL put options	—		—			403			403
Oil and natural gas fixed price swaps	—		132			—			132
NGL fixed price swaps	—		—			(2,911		)	(2,911		)
Contingent consideration	—		—			(6,320		)	(6,320		)
Total	$	—	$	103		$	(8,837	)	$	(8,734	)

The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended September 30, 2013 and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,			Nine Months Ended September 30,
	2013			2014			2013
Beginning balance	$	1,866		$	(2,517	)	$	(112	)
Loss on derivative contracts	(3,277		)	(2,432		)	(1,522		)
Transfers out (1)	—			2,843			—
Cash paid upon settlement	446			2,106			669
Ending balance	$	(965	)	$	—		$	(965	)
Unrealized losses included in earnings relating to derivatives held at period end	$	(2,677	)	$	—		$	(884	)

__________

(1) Fair values related to the Company’s natural gas collars, natural gas and NGL put options and NGL fixed price swaps were transferred from Level 3 to Level 2 in the second quarter of 2014 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the three and nine months ended September 30, 2013, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

See Note 6 "Derivative Contracts" for additional discussion of our derivative contracts. See Note 3 "Contingent Consideration" for a reconciliation of activity for contingent consideration during the three and nine months ended September 30, 2014.

Fair Value of Financial Instruments

Credit Facility. The carrying amount of the credit facility of $92.25 million and $78.5 million as of September 30, 2014 and December 31, 2013, respectively, approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings.

Notes Payable. The carrying value of our notes payable of $21.9 million and $2.2 million at September 30, 2014 and December 31, 2013 approximated fair value based on rates applicable to similar instruments. 

The credit facility and notes payable are classified as a Level 2 item within the fair value hierarchy.

Fair Value on a Non-Recurring Basis

The Partnership performs valuations on a non-recurring basis primarily as it relates to the consideration, assets acquired, and liabilities assumed related to acquisitions. See Note 2 "Acquisitions" for discussion of these valuations.

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Goodwill and Intangible Assets

9 Months Ended

Sep. 30, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible Assets

Goodwill and Intangible Assets

Goodwill

Goodwill represents the estimated future economic benefits arising from other assets acquired in business combinations that could not be individually identified and separately recognized. See Note 2 "Acquisitions" for discussion of our business acquisitions. Such goodwill is not deductible for tax purposes. Goodwill has been allocated to the oilfield services segment. A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2013 to September 30, 2014 is as follows (in thousands):

Goodwill at December 31, 2013	$	23,974
Additions:
MCCS Acquisition	4,060
Services Acquisition	11,664
Change due to purchase price allocation adjustments (1)	3,836
Goodwill at September 30, 2014	$	43,534

__________

(1)    Includes adjustments totaling $3.8 million during the three months ended September 30, 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. See Note 2 "Acquisitions" for discussion of the purchase price allocation adjustments.

Intangible Assets

Intangible assets were identified in certain of the acquisitions during 2013 and 2014. See Note 2 "Acquisitions" for discussion of our business acquisitions. Intangible assets are amortized over the expected cash flow period for customer relationships and over the agreement period for the non-compete agreements. Amortization expense for the three and nine months ended September 30, 2014 was $9.4 million and $15.6 million, respectively.

The Partnership's intangible assets at September 30, 2014 and December 31, 2013 consist of the following (in thousands):    

	September 30, 2014		December 31, 2013
Customer relationships - MCE Acquisition	$	36,772	$	36,772
Customer relationships - Services Acquisition	64,200		—
Non-compete agreements - Services Acquisition	4,500		—
Customer relationships - MCCS Acquisition	1,700		—
Total intangible assets	107,172		36,772
Less: accumulated amortization	17,359		1,763
Intangible assets, net	$	89,813	$	35,009

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Earnings per Unit

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings per Unit

Earnings per Unit

The Partnership’s net income is allocated to the common, subordinated and general partner unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the Partnership’s LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. Basic and diluted net income per unit is calculated by dividing net income 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 nine months ended September 30, 2014, LTIP awards of 3,257 and 9,664 common units, respectively, were excluded from the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of September 30, 2013. Therefore, basic and diluted earnings per unit are the same for the three and nine months ended September 30, 2013.

Basic and diluted earnings per unit for the three and nine months ended September 30, 2014 and 2013 were computed as follows (in thousands, except per unit amounts):

	Three Months Ended   September 30, 2014									Nine Months Ended   September 30, 2014
	Common Units			Subordinated Units			General Partner			Common Units			Subordinated Units			General Partner
Net loss	$	(2,599	)	$	(371	)	$	(26	)	$	(2,503	)	$	(411	)	$	(29	)
Weighted average units outstanding	15,429			2,205			155			12,646			2,205			155
Basic and diluted loss per unit	$	(0.17	)	$	(0.17	)	$	(0.17	)	$	(0.20	)	$	(0.19	)	$	(0.19	)

	Three Months Ended   September 30, 2013									Nine Months Ended   September 30, 2013
	Common Units			Subordinated Units			General Partner			Common Units			Subordinated Units			General Partner
Net loss (1)	$	(1,473	)	$	(479	)	$	(34	)	$	(76	)	$	(430	)	$	(29	)
Weighted average units outstanding	6,774			2,205			155			6,480			2,205			155
Basic and diluted loss per unit	$	(0.22	)	$	(0.22	)	$	(0.22	)	$	(0.01	)	$	(0.20	)	$	(0.19	)

__________

(1) Reflects net loss from February 13, 2013 through September 30, 2013 for the nine months ended September 30, 2013.

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Derivative Contracts - Commodity Derivative Positions Natural Gas Swaps (Details) (Natural Gas Swaps)	9 Months Ended
	Sep. 30, 2014 MMBTU
2014
Derivative [Line Items]
Volumes (MMBtu)	176,795
Derivative, Swap Type, Average Fixed Price	4.09
2015
Derivative [Line Items]
Volumes (MMBtu)	800,573
Derivative, Swap Type, Average Fixed Price	4.25
2016
Derivative [Line Items]
Volumes (MMBtu)	629,301
Derivative, Swap Type, Average Fixed Price	4.37

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Business Segment Information - Summary of Segment Operating Activities (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]
Revenue	$ 56,424		$ 12,431		$ 110,669		$ 32,440
Direct operating expenses	29,877		3,985		51,101		10,698
Segment margin	26,547		8,446		59,568		21,742
General and administrative	13,785		1,353		22,835		11,452	[1]
Depreciation, depletion, amortization and accretion	17,837		4,972		37,548		11,831
Operating (loss) income	(5,075)		2,121		(815)		(1,541)
Property, Plant and Equipment, Additions	4,559	[2]	14,745	[2]	26,010	[2]	18,261	[2]
Total assets	434,524				434,524				254,710
Exploration and Production
Segment Reporting Information [Line Items]
Revenue	15,561		12,431		51,130		32,440
Direct operating expenses	5,562		3,985		16,252		10,698
Segment margin	9,999		8,446		34,878		21,742
General and administrative	7,354		1,353		13,220		11,452	[1]
Depreciation, depletion, amortization and accretion	6,834		4,972		19,692		11,831
Operating (loss) income	(4,189)		2,121		1,966		(1,541)
Property, Plant and Equipment, Additions	824	[2]	14,745	[2]	19,284	[2]	18,261	[2]
Total assets	194,541				194,541				181,440
Oilfield Services
Segment Reporting Information [Line Items]
Revenue	40,863	[3]	0	[3]	59,539	[3]	0	[3]
Direct operating expenses	24,315	[3]	0	[3]	34,849	[3]	0	[3]
Segment margin	16,548	[3]	0	[3]	24,690	[3]	0	[3]
General and administrative	6,431	[3]	0	[3]	9,615	[3]	0	[1],[3]
Depreciation, depletion, amortization and accretion	11,003	[3]	0	[3]	17,856	[3]	0	[3]
Operating (loss) income	(886)	[3]	0	[3]	(2,781)	[3]	0	[3]
Property, Plant and Equipment, Additions	3,735	[2]	0	[2]	6,726	[2],[3]	0	[2],[3]
Total assets	$ 239,983	[3]			$ 239,983	[3]			$ 73,270	[3]

[1] Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

[2] On an accrual basis and exclusive of acquisitions.

[3] The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion.

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Derivative Contracts - Offsetting Commodity Derivative Assets and Liabilities (Details) (Commodity, USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Gross amounts of recognized assets	$ 1,630	$ 2,980
Gross Amounts Offset	(410)	(2,190)
Net Amounts Presented	1,220	790
Gross amounts of recognized liabilities	1,055	5,394
Gross Amounts Offset	(410)	(2,190)
Net Amounts Presented	645	3,204
Current Assets
Derivative [Line Items]
Gross amounts of recognized assets	1,065	1,342
Gross Amounts Offset	(404)	(1,212)
Net Amounts Presented	661	130
Long-term Assets
Derivative [Line Items]
Gross amounts of recognized assets	565	1,638
Gross Amounts Offset	(6)	(978)
Net Amounts Presented	559	660
Current Liabilities
Derivative [Line Items]
Gross amounts of recognized liabilities	1,012	4,379
Gross Amounts Offset	(404)	(1,212)
Net Amounts Presented	608	3,167
Long-term Liabilities
Derivative [Line Items]
Gross amounts of recognized liabilities	43	1,015
Gross Amounts Offset	(6)	(978)
Net Amounts Presented	$ 37	$ 37

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Derivative Contracts - Commodity Derivative Positions Oil Swaps (Details) (Oil Swaps)	9 Months Ended
	Sep. 30, 2014 bbl
2014
Derivative [Line Items]
Volumes (Bbls)	6,900
Derivative, Swap Type, Average Fixed Price	103.52
2015
Derivative [Line Items]
Volumes (Bbls)	39,411
Derivative, Swap Type, Average Fixed Price	88.90
2016
Derivative [Line Items]
Volumes (Bbls)	36,658
Derivative, Swap Type, Average Fixed Price	86.00

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2013 to September 30, 2014 is as follows (in thousands):

Asset retirement obligation at December 31, 2013	$	3,455
Liability incurred upon acquiring and drilling wells	235
Liability settled or disposed	(32		)
Accretion	219
Asset retirement obligation at September 30, 2014	$	3,877

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Acquisitions - Pro Forma Results of Operations (Details) (USD $)	3 Months Ended		9 Months Ended		3 Months Ended	9 Months Ended
	Sep. 30, 2013 2013 and 2014 Material Acquisitions [Member]		Sep. 30, 2013 2013 and 2014 Material Acquisitions [Member]		Sep. 30, 2014 2014 Material Acquisitions	Sep. 30, 2014 2014 Material Acquisitions		Sep. 30, 2014 Acquisition-related Costs 2014 Material Acquisitions	Sep. 30, 2013 Acquisition-related Costs 2014 Material Acquisitions
Business Acquisition [Line Items]
Revenue	$ 65,673,000		$ 136,851,000			$ 172,590,000
Net income	(3,971,000)	[1]	(10,647,000)	[1]		5,084,000	[2]
Net income per common unit (1):
Basic (in usd per unit)	$ (0.24)	[1]	$ (0.83)	[1]		$ 0.31	[2]
Diluted (in usd per unit)	$ (0.24)	[1]	$ (0.83)	[1]		$ 0.31	[2]
Acquisition costs and transaction bonuses					$ (400,000)	$ (3,600,000)		$ (24,300,000)	$ (1,600,000)

[1] Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the nine months ended September 30, 2013.

[2] Excludes $24.3 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.

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Business Segment Information

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Business Segment Information

Business Segment Information

The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties and its general and administrative expenses include certain costs of our corporate administrative functions and changes in the fair value of contingent consideration obligations related to all acquisitions. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, as well as well testing and flowback services. Our oilfield services segment is the aggregation of multiple operating segments that meet the criteria for aggregation due to the economic similarities as well as the similarities in the nature of the services provided, customers served and industry regulations monitored.

Management evaluates the performance of the Partnership’s business segments based on the excess of revenue over direct operating expenses or segment margin. Summarized financial information concerning the Partnership’s segments is shown in the following tables (in thousands):

	Exploration and Production			Oilfield Services (1)			Total
Three Months Ended September 30, 2014
Revenues	$	15,561		$	40,863		$	56,424
Direct operating expenses	5,562			24,315			29,877
Segment margin	$	9,999		$	16,548		$	26,547
General and administrative expenses	7,354			6,431			13,785
Depreciation, depletion, amortization and accretion	6,834			11,003			17,837
Loss from operations	$	(4,189	)	$	(886	)	$	(5,075	)
Capital expenditures (2)	$	824		$	3,735		$	4,559
Three Months Ended September 30, 2013
Revenues	$	12,431		$	—		$	12,431
Direct operating expenses	3,985			—			3,985
Segment margin	$	8,446		$	—		$	8,446
General and administrative expenses	1,353			—			1,353
Depreciation, depletion, amortization and accretion	4,972			—			4,972
Income from operations	$	2,121		$	—		$	2,121
Capital expenditures (2)	$	14,745		$	—		$	14,745

__________

(1) The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion.

(2) On an accrual basis and exclusive of acquisitions.

	Exploration and Production			Oilfield Services (1)			Total
Nine Months Ended September 30, 2014
Revenues	$	51,130		$	59,539		$	110,669
Direct operating expenses	16,252			34,849			51,101
Segment margin	$	34,878		$	24,690		$	59,568
General and administrative expenses	13,220			9,615			22,835
Depreciation, depletion, amortization and accretion	19,692			17,856			37,548
Income (loss) from operations	$	1,966		$	(2,781	)	$	(815	)
Capital expenditures (2)	$	19,284		$	6,726		$	26,010
At September 30, 2014
Total assets	$	194,541		$	239,983		$	434,524
Nine Months Ended September 30, 2013
Revenues	$	32,440		$	—		$	32,440
Direct operating expenses	10,698			—			10,698
Segment margin	$	21,742		$	—		$	21,742
General and administrative expenses (3)	11,452			—			11,452
Depreciation, depletion, amortization and accretion	11,831			—			11,831
Loss from operations	$	(1,541	)	$	—		$	(1,541	)
Capital expenditures (2)	$	18,261		$	—		$	18,261
At December 31, 2013
Total assets	$	181,440		$	73,270		$	254,710

__________

(1) The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See Note 2 "Acquisitions" for discussion.

(2) On an accrual basis and exclusive of acquisitions.

(3) Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

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Debt (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Schedule of Debt

The Partnership's debt consists of the following (in thousands):    

	September 30, 2014		December 31, 2013
Credit facility	$	92,250	$	78,500
Notes payable	21,889		2,233
Line of credit	3,294		—
Total debt	117,433		80,733
Less: current maturities of long-term debt	21,132		719
Long-term debt	$	96,301	$	80,014

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Acquisitions - Purchase Price Allocation of EFS and RPS Acquisition (Details) (USD $)				0 Months Ended		3 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Jun. 26, 2014 EFS and RPS		Sep. 30, 2014 EFS and RPS		Jun. 26, 2014 EFS and RPS Employees EFS and RPS
Business Acquisition [Line Items]
Cash				$ 57,348,000
Fair value of common units granted				33,106,000	[1]
Common units granted for the benefit of EFS and RPS employees								724,000	[2]
Contingent consideration	36,854,000	26,609,000	6,320,000	21,984,000	[3]	21,053,000	[3]
Total fair value of consideration				113,162,000
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Consideration Transferred						$ (4,800,000)

[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 and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition are excluded from consideration based on the future service requirement for vesting. See Note 9 "Equity" for additional discussion of phantom units.

[3] The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 3 "Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. During the three months ended September 30, 2014, a purchase price allocation adjustment was made for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

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

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Condensed Consolidated Statements of Unitholders' Equity (Unaudited) (USD $) In Thousands, except Share data, unless otherwise specified	Total	Common	Subordinated	General Partnership	Noncontrolling Interest
Beginning Balance at Dec. 31, 2013	$ 147,253	$ 151,773	$ (17,334)	$ (1,174)	$ 13,988
Beginning Balance (in units) at Dec. 31, 2013		9,599,578	2,205,000	155,102
Increase (Decrease) in Partners' Capital [Roll Forward]
Issuance of common units, net of offering costs (in units)		3,450,000
Issuance of common units, net of offering costs	76,191	76,191
Offering cost related to 2013 private placement paid in 2014	(100)	(100)
Issuance of common units in acquisitions (in units)		1,964,957
Issuance of common units in acquisitions	45,447	43,938			1,509
Equity-based compensation (in units)		425,846
Equity-based compensation	1,906	1,906
Distributions to unitholders	(25,905)	(21,556)	(3,837)	(270)	(242)
Net (loss) income	(2,701)	(2,503)	(411)	(29)	242
Ending Balance at Sep. 30, 2014	$ 242,091	$ 249,649	$ (21,582)	$ (1,473)	$ 15,497
Ending Balance (in units) at Sep. 30, 2014		15,440,381	2,205,000	155,102

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Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Debt

Debt

The Partnership's debt consists of the following (in thousands):    

	September 30, 2014		December 31, 2013
Credit facility	$	92,250	$	78,500
Notes payable	21,889		2,233
Line of credit	3,294		—
Total debt	117,433		80,733
Less: current maturities of long-term debt	21,132		719
Long-term debt	$	96,301	$	80,014

Senior Secured Revolving Credit Facility

The Partnership has a senior secured revolving credit facility that is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below, (the "credit facility"). As of September 30, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of all subsidiaries. The credit facility matures in February 2017.

Additionally, the credit facility contains various covenants and restrictive provisions that, among other things, limit the ability of the Partnership to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. Notwithstanding the foregoing, the credit facility permits the Partnership to make distributions to its common unit holders in an amount not to exceed "available cash" (as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership) if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed 90%. As of September 30, 2014, the Partnership was in compliance with all covenants under the credit facility.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At September 30, 2014 and December 31, 2013, the average annual interest rate on borrowings outstanding under the credit facility was 3.25%. At September 30, 2014, the borrowing base under the credit facility was $102.5 million with $10.25 million of available borrowing capacity and no available borrowing capacity before restriction on distribution occurs. In October 2014, the Partnership repaid $9.25 million in borrowings under the credit facility, which increases the amount of available borrowing capacity before restriction on distribution occurs by $9.25 million.

The semi-annual redetermination of the borrowing base on our credit facility is currently in process. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. Based on our reserve estimates and applicable commodity pricing, we may have a decrease to our borrowing base as a result of the redetermination. As of November 13, 2014, the redetermination of our borrowing base had not been finalized.

Notes Payable

The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. These notes range from 12-60 months in duration with maturity dates from August 2015 through April 2018 and carry variable interest rates ranging from 5.28% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. In August 2014, MCES entered into $3.5 million of additional notes payable. At September 30, 2014, the Partnership had $7.7 million outstanding under the MCES notes payable as of September 30, 2014.

In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on term loans held by EFS. These term loans had a balance of $14.2 million as of September 30, 2014 and mature on June 26, 2015. The term loans have a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at September 30, 2014, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The term loans are collateralized by various assets of the parties to the agreement and guaranteed by MCE and former owners of EFS and RPS. The Partnership is required to maintain a reserve bank account into which the lesser of $0.3 million or 100% of excess cash flow (as defined in the loan agreement) shall be deposited quarterly and used to fund an additional annual payment on September 30th of each year during the term of the loans.

The EFS term loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, beginning October 1, 2014, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0 (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $4.0 million, in each case as more fully described in the loan agreement.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. Interest only payments are due monthly with the line of credit maturing in February 2015. The line of credit replaced MCES' factoring payable agreement described in Note 5 "Factoring Payable." Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at September 30, 2014. The line of credit is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. Based on the outstanding balance of $3.3 million, there was $0.7 million of available borrowing capacity at September 30, 2014.

The line of credit contained a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of September 30, 2014, MCES was in compliance with this covenant under the line of credit.

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Derivative Contracts - Commodity Derivative Positions of Oil Collars - Three Way (Details) (Oil Collars - Three Way, 2015)	9 Months Ended
	Sep. 30, 2014 bbl
Oil Collars - Three Way | 2015
Derivative [Line Items]
Volumes (Bbls)	36,500
Sold Put (in usd per Bbl)	77.50
Purchased Put (in usd per Bbl)	92.50
Ceiling Price (in usd per Bbl)	102.60

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Commitments and Contingencies (Details) (USD $)	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]
Annual maintenance drilling budget	$ 8,200,000.0
Maintenance budget incurred to date	10,500,000
Estimated contingency loss	$ 250,000

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Fair Value Measurements - Derivative Assets and Contingent Consideration Measured at Fair Value (Details) (USD $)	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Inputs, Level 3	Sep. 30, 2013 Fair Value, Inputs, Level 3	Jun. 30, 2013 Fair Value, Inputs, Level 3	Dec. 31, 2012 Fair Value, Inputs, Level 3	Sep. 30, 2014 Fair Value, Measurements, Recurring	Dec. 31, 2013 Fair Value, Measurements, Recurring	Sep. 30, 2014 Fair Value, Measurements, Recurring Fair Value, Inputs, Level 1	Dec. 31, 2013 Fair Value, Measurements, Recurring Fair Value, Inputs, Level 1	Sep. 30, 2014 Fair Value, Measurements, Recurring Fair Value, Inputs, Level 2	Dec. 31, 2013 Fair Value, Measurements, Recurring Fair Value, Inputs, Level 2	Sep. 30, 2014 Fair Value, Measurements, Recurring Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Measurements, Recurring Fair Value, Inputs, Level 3	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil And Natural Gas Collars	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil And Natural Gas Collars Fair Value, Inputs, Level 1	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil And Natural Gas Collars Fair Value, Inputs, Level 2	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil And Natural Gas Collars Fair Value, Inputs, Level 3	Sep. 30, 2014 Fair Value, Measurements, Recurring Natural Gas and NGL Puts	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas and NGL Puts	Sep. 30, 2014 Fair Value, Measurements, Recurring Natural Gas and NGL Puts Fair Value, Inputs, Level 1	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas and NGL Puts Fair Value, Inputs, Level 1	Sep. 30, 2014 Fair Value, Measurements, Recurring Natural Gas and NGL Puts Fair Value, Inputs, Level 2	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas and NGL Puts Fair Value, Inputs, Level 2	Sep. 30, 2014 Fair Value, Measurements, Recurring Natural Gas and NGL Puts Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas and NGL Puts Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Collar	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Collar Fair Value, Inputs, Level 1	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Collar Fair Value, Inputs, Level 2	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Collar Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas Collars	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas Collars Fair Value, Inputs, Level 1	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas Collars Fair Value, Inputs, Level 2	Dec. 31, 2013 Fair Value, Measurements, Recurring Natural Gas Collars Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Put Options	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Put Options Fair Value, Inputs, Level 1	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Put Options Fair Value, Inputs, Level 2	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil Put Options Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil and Natural Gas Swaps	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil and Natural Gas Swaps Fair Value, Inputs, Level 1	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil and Natural Gas Swaps Fair Value, Inputs, Level 2	Dec. 31, 2013 Fair Value, Measurements, Recurring Oil and Natural Gas Swaps Fair Value, Inputs, Level 3	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil, Natural Gas and NGL Swaps	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil, Natural Gas and NGL Swaps Fair Value, Inputs, Level 1	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil, Natural Gas and NGL Swaps Fair Value, Inputs, Level 2	Sep. 30, 2014 Fair Value, Measurements, Recurring Oil, Natural Gas and NGL Swaps Fair Value, Inputs, Level 3	Dec. 31, 2013 Fair Value, Measurements, Recurring NGL Swaps	Dec. 31, 2013 Fair Value, Measurements, Recurring NGL Swaps Fair Value, Inputs, Level 1	Dec. 31, 2013 Fair Value, Measurements, Recurring NGL Swaps Fair Value, Inputs, Level 2	Dec. 31, 2013 Fair Value, Measurements, Recurring NGL Swaps Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Net fair value of derivative				$ 0	$ (2,517,000)	$ (965,000)	$ 1,866,000	$ (112,000)									$ 157,000	$ 0	$ 157,000	$ 0	$ 539,000	$ 403,000	$ 0	$ 0	$ 539,000	$ 0	$ 0	$ 403,000	$ (57,000)	$ 0	$ (57,000)	$ 0	$ (9,000)	$ 0	$ 0	$ (9,000)	$ 28,000	$ 0	$ 28,000	$ 0	$ 132,000	$ 0	$ 132,000	$ 0	$ (121,000)	$ 0	$ (121,000)	$ 0	$ (2,911,000)	$ 0	$ 0	$ (2,911,000)
Contingent consideration	(36,854,000)	(26,609,000)	(6,320,000)						(36,854,000)	(6,320,000)	0	0	0	0	(36,854,000)	(6,320,000)
Total									$ (36,279,000)	$ (8,734,000)	$ 0	$ 0	$ 575,000	$ 103,000	$ (36,854,000)	$ (8,837,000)

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Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2014

Derivative [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following table summarizes our derivative contracts on a gross basis, the effects of netting assets and liabilities for which the right of offset exists (in thousands):

September 30, 2014	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,065	$	(404	)	$	661
Commodity derivatives - long-term assets	565		(6		)	559
Total	$	1,630	$	(410	)	$	1,220
Liabilities:
Commodity derivatives - current liabilities	$	1,012	$	(404	)	$	608
Commodity derivatives - long-term liabilities	43		(6		)	37
Total	$	1,055	$	(410	)	$	645

December 31, 2013	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,342	$	(1,212	)	$	130
Commodity derivatives - long-term assets	1,638		(978		)	660
Total	$	2,980	$	(2,190	)	$	790
Liabilities:
Commodity derivatives - current liabilities	$	4,379	$	(1,212	)	$	3,167
Commodity derivatives - long-term liabilities	1,015		(978		)	37
Total	$	5,394	$	(2,190	)	$	3,204

The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended September 30, 2013 and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,			Nine Months Ended September 30,
	2013			2014			2013
Beginning balance	$	1,866		$	(2,517	)	$	(112	)
Loss on derivative contracts	(3,277		)	(2,432		)	(1,522		)
Transfers out (1)	—			2,843			—
Cash paid upon settlement	446			2,106			669
Ending balance	$	(965	)	$	—		$	(965	)
Unrealized losses included in earnings relating to derivatives held at period end	$	(2,677	)	$	—		$	(884	)

The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were measured at fair value on a recurring basis (in thousands):

September 30, 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	$	—	$	157		$	—		$	157
Oil, natural gas and NGL put options	—		539			—			539
Oil, natural gas and NGL fixed price swaps	—		(121		)	—			(121		)
Contingent consideration	—		—			(36,854		)	(36,854		)
Total	$	—	$	575		$	(36,854	)	$	(36,279	)

December 31, 2013	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
Oil collars	$	—	$	(57	)	$	—		$	(57	)
Natural gas collars	—		—			(9		)	(9		)
Oil put options	—		28			—			28
Natural gas and NGL put options	—		—			403			403
Oil and natural gas fixed price swaps	—		132			—			132
NGL fixed price swaps	—		—			(2,911		)	(2,911		)
Contingent consideration	—		—			(6,320		)	(6,320		)
Total	$	—	$	103		$	(8,837	)	$	(8,734	)

Schedule of Derivative Instruments

At September 30, 2014, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.
Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.
Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the put option and the fixed price.
Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

Derivative Instruments, Gain (Loss)

The following table presents gain (loss) on our derivative contracts as included in the accompanying unaudited statements of operations for the three and nine months ended September 30, 2014 and 2013 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013			2014			2013
Total gain (loss) on derivative contracts, net (1)	$	3,768	$	(3,453	)	$	(760	)	$	(2,597	)

Oil Collar

Derivative [Line Items]

Schedule of Derivative Instruments

The following tables present our derivative instruments outstanding as of September 30, 2014:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2014	23,763	$	80.00	$	103.50
2015	42,649	$	80.00	$	93.25

Oil Collars - Three Way

Derivative [Line Items]

Schedule of Derivative Instruments

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	36,500	$	77.50	$	92.50	$	102.60

Natural Gas Collars

Derivative [Line Items]

Schedule of Derivative Instruments

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2014	260,751	$	4.00	$	4.41
2015	1,362,382	$	4.00	$	4.32

Oil Options

Derivative [Line Items]

Schedule of Derivative Instruments

Oil put options	Volumes (Bbls)	Floor Price
2014	7,418	$	80.00

Natural Gas Options

Derivative [Line Items]

Schedule of Derivative Instruments

Natural gas put options	Volumes (MMBtu)	Floor Price
2014	99,034	$	3.50
2015	798,853	$	3.50
2016	930,468	$	3.50

Natural Gas Liquid Options

Derivative [Line Items]

Schedule of Derivative Instruments

NGL put options	Volumes (Bbls)	Average Floor Price
2014	5,535	$	63.19

Oil Swaps

Derivative [Line Items]

Schedule of Derivative Instruments

Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	6,900	$	103.52
2015	39,411	$	88.90
2016	36,658	$	86.00

Natural Gas Swaps

Derivative [Line Items]

Schedule of Derivative Instruments

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2014	176,795	$	4.09
2015	800,573	$	4.25
2016	629,301	$	4.37

Natural Gas Liquid Swaps

Derivative [Line Items]

Schedule of Derivative Instruments

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2014	168,924	$	39.44
2015	84,793	$	75.18

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Goodwill and Intangible Assets - Schedule of Finite-Lived Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	$ 107,172	$ 36,772
Less: accumulated amortization	17,359	1,763
Intangible assets, net	89,813	35,009
MidCentral Energy Services | Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	36,772	36,772
EFS and RPS | Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	64,200	0
EFS and RPS | Noncompete Agreements
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	4,500	0
MCCS | Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Total intangible assets	$ 1,700	$ 0

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

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Commitments

The Partnership is a party to various agreements under which it has rights and obligations to participate in the acquisition and development of undeveloped properties held and to be acquired by Scintilla and New Dominion. These properties will be held by New Dominion for the benefit of the Partnership pending development of the properties. The Partnership is required by its underlying agreements with New Dominion to pay certain acreage fees to reimburse New Dominion for the cost of the acreage attributable to the Partnership’s working interest when invoiced by New Dominion. The Partnership recognizes an asset and corresponding liability as the acreage costs are incurred by New Dominion. See Note 11 "Related Party Transactions."  The agreements require us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. There are significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements. The agreements also require us to pay New Dominion our proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into a development agreement (the "Development Agreement") with NSEC and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, the Partnership has agreed to maintain an average annual maintenance drilling budget of at least $8.2 million to drill certain of the Partnership’s proved undeveloped locations and maintain the Partnership’s producing wells. As of September 30, 2014, we had incurred $10.5 million towards the annual maintenance drilling budget.

See Note 3 "Contingent Consideration" for discussion of contingencies related to certain acquisitions.

Legal Matters

New Dominion is a defendant in a legal proceeding arising in the normal course of its business, which may impact the Partnership as described below.

In the case of Mattingly v. Equal Energy, LLC, New Dominion is a named defendant. In this case, the plaintiffs assert claims on behalf of a class of royalty owners in wells operated by New Dominion and others from which natural gas is sold by New Dominion to Scissortail Energy, LLC ("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. The case was originally filed in the District Court of Creek County, Oklahoma and was removed by the defendants to the federal court but was remanded to state court on August 1, 2011. A hearing on the matter was held August 27, 2014 at which Scissortail’s motion to dismiss was granted with prejudice and New Dominion’s motion to dismiss was granted in part.  A hearing date for class certification is expected to be set in November 2014.

Any liability on the part of New Dominion, as 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.