New Source Energy Partners (NSLP) 10-Q 2015 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

(MARK ONE)

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

For the quarterly period ended March 31, 2015

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 þ 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 þ	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 þ

As of May 6, 2015, the registrant had 16,558,236 common units and 2,205,000 subordinated units outstanding.

NEW SOURCE ENERGY PARTNERS L.P.

Form 10-Q

Quarter Ended March 31, 2015

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)	5
		Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	5
		Condensed Consolidated Statements of Operations for the three months ended March 31, 2015 and 2014	7
		Condensed Consolidated Statement of Unitholders' Equity for the three months ended March 31, 2015	8
		Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2015 and 2014	9
		Notes to Condensed Consolidated Financial Statements	10
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47
	Item 4.	Controls and Procedures	49
PART II – OTHER INFORMATION
	Item 1.	Legal Proceedings	51
	Item 1A.	Risk Factors	52
	Item 6.	Exhibits	57

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;

• "MCE" refers collectively to MidCentral Energy Partners L.P. and MidCentral Energy GP, LLC;

• "MCE Acquisition" refers to the Partnership's acquisition of 100% of the equity interests in MCE in November 2013, except for the Class B units that were retained by certain of the sellers;

• "MCES" refers to MidCentral Energy Services LLC;

• "MCLP" refers specifically to MidCentral Energy Partners L.P.;

• “MCE GP” refers specifically to MidCentral Energy 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;

• "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;

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

• “Series A Preferred Units” refers to our 11.00% Series A Cumulative Convertible Preferred Units.

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 "Risk Factors" in Item 1A of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the "2014 Form 10-K").

4

PART I: Financial Information

ITEM 1. Financial Statements

New Source Energy Partners L.P. Condensed Consolidated Balance Sheets (Unaudited)
	March 31, 2015			December 31, 2014
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash	$	1,531		$	5,504
Restricted cash	85			350
Accounts receivable, net	24,404			31,919
Accounts receivable-related parties, net	5,519			4,946
Derivative contracts	7,292			8,248
Inventory	4,564			4,236
Other current assets	2,850			2,489
Total current assets	46,245			57,692
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	333,205			332,413
Less: Accumulated depreciation, depletion, amortization, and impairment	(201,548		)	(153,734		)
Total oil and natural gas properties, net	131,657			178,679
Property and equipment, net	72,744			68,886
Intangible assets, net	51,211			56,377
Goodwill	9,315			9,315
Derivative contracts	1,659			1,818
Other assets	2,702			2,779
Total assets	$	315,533		$	375,546

5

New Source Energy Partners L.P. Condensed Consolidated Balance Sheets - continued (Unaudited)
	March 31, 2015			December 31, 2014
	(in thousands, except unit amounts)
LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	16,152		$	15,326
Accounts payable-related parties	266			2,318
Factoring payable	11,352			13,152
Contingent consideration payable	11,572			11,572
Other current liabilities	122			113
Current portion of long-term debt	12,277			11,825
Total current liabilities	51,741			54,306
Long-term debt	94,804			95,218
Contingent consideration payable	10,633			10,801
Asset retirement obligations	3,639			3,568
Other liabilities	252			339
Total liabilities	161,069			164,232
Commitments and contingencies (Note 12)
Unitholders' equity:
Common units 16,403,134 units issued and outstanding at March 31, 2015 and 16,160,381 units issued and outstanding at December 31, 2014	180,014			231,510
Common units held in escrow	(4,680		)	(6,955		)
Subordinated units 2,205,000 units issued and outstanding at March 31, 2015 and December 31, 2014	(35,845		)	(28,717		)
General partner's units 155,102 units issued and outstanding at March 31, 2015 and December 31, 2014	(2,445		)	(1,944		)
Total New Source Energy Partners L.P. unitholders' equity	137,044			193,894
Noncontrolling interest	17,420			17,420
Total unitholders' equity	154,464			211,314
Total liabilities and unitholders' equity	$	315,533		$	375,546

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

6

New Source Energy Partners L.P.

Condensed Consolidated Statements of Operations

(Unaudited)

		Three Months Ended March 31,
		2015			2014
	(in thousands, except per unit amounts)
Revenues:
Oil sales		$	1,692		$	3,947
Natural gas sales		1,843			5,367
NGL sales		3,032			9,537
Oilfield services		31,550			8,576
Total revenues		38,117			27,427
Operating costs and expenses:
Oil, natural gas and NGL production		4,055			4,503
Production taxes		311			879
Cost of providing oilfield services		23,059			4,566
Depreciation, depletion and amortization		12,347			9,279
Accretion		74			68
Impairment of oil and natural gas properties		43,119			—
General and administrative		12,234			5,560
Total operating costs and expenses		95,199			24,855
Operating (loss) income		(57,082		)	2,572
Other income (expense):
Interest expense		(1,348		)	(969		)
Gain (loss) on derivative contracts, net		1,224			(3,132		)
Other income (expense)		34			(2		)
Net loss		(57,172		)	(1,531		)
Less: net income attributable to noncontrolling interest		—			—
Net loss attributable to New Source Energy Partners L.P.		$	(57,172	)	$	(1,531	)
Net loss per unit:
Net loss per general partner unit		$	(3.03	)	$	(0.12	)
Net loss per subordinated unit		$	(3.23	)	$	(0.12	)
Net loss per common unit		$	(3.03	)	$	(0.12	)

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

7

New Source Energy Partners L.P.

Condensed Consolidated Statement of Unitholders' Equity

For the Three Months Ended March 31, 2015

(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, 2014	16,160,381	$	224,555		2,205,000	$	(28,717	)	155,102	$	(1,944	)	$	17,420	$	211,314
Acquisition from unitholder	—	(227		)	—	—			—	—			—		(227		)
Equity-based compensation	242,753	3,861			—	—			—	—			—		3,861
Distributions to unitholders	—	(3,281		)	—	—			—	(31		)	—		(3,312		)
Net loss	—	(49,574		)	—	(7,128		)	—	(470		)	—		(57,172		)
Balance, March 31, 2015	16,403,134	$	175,334		2,205,000	$	(35,845	)	155,102	$	(2,445	)	$	17,420	$	154,464

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

8

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

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

9

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

1.  Basis of Presentation

Nature of Business. We are a Delaware limited partnership formed in October 2012 to own and acquire oil and natural gas properties in the United States. We are engaged in the production of onshore oil and natural gas properties that extend across conventional resource reservoirs in east-central Oklahoma. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation. In addition, we are engaged in oilfield services through our oilfield services subsidiaries. Our oilfield services business provides wellsite services during the drilling and completion stages of a well, including full service blowout prevention installation, pressure testing services, including certain ancillary equipment necessary to perform such services, well testing and flowback services to companies in the oil and natural gas industry primarily in Oklahoma, Texas, New Mexico, Kansas, Pennsylvania, Ohio and West Virginia.

Principles of Consolidation. The unaudited condensed consolidated financial statements include the accounts of the Partnership and its wholly owned and majority owned subsidiaries. Noncontrolling interest represents third-party ownership interest in a majority owned subsidiary of the Partnership and is included as a component of equity in the consolidated balance sheet and consolidated statement of unitholders' equity. All significant intercompany accounts and transactions have been eliminated in consolidation.

Interim Financial Statements. The accompanying condensed consolidated financial statements as of December 31, 2014 have been derived from the audited financial statements contained in the Partnership’s 2014 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2014 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s accompanying unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2014 Form 10-K.

Significant Accounting Policies. For a description of the Partnership’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2014 Form 10-K.

Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Partnership's previously reported results of operations.

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

Recently Issued Accounting Standard. In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, ("ASU 2014-09"), which revises the guidance on revenue recognition by providing a single, principles-based method for companies to use to account for revenue arising from contracts with customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires disclosures enabling users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard permits the use of either the retrospective or cumulative effect transition method. ASU 2014-09 is effective for fiscal years beginning after December 15, 2016. Early application is not permitted. We are in the process of assessing which transition method we will apply and the potential impact of ASU 2014-09 on the Partnership's financial statements. In April 2015, the FASB voted to propose to defer the effective date by one year.

10

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. We are currently evaluating the effect, if any, the guidance will have on our related disclosures.

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction from the carrying amount of the debt. The new standard does not change the recognition and measurement of debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect the guidance will have on our consolidated financial statements and related disclosures.

2.  Acquisitions

The Partnership completed acquisitions during 2014, as described below. The acquisitions of Erick Flowback Services LLC ("EFS"), Rod's Production Services, L.L.C. ("RPS") and MidCentral Completion Services, LLC ("MCCS") expanded the Partnership's oilfield services segment. The acquisition of MCCS was with related parties. See Note 9 "Related Party Transactions." In 2014, we also acquired working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma to expand the Partnership's exploration and production segment.

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy as described in Note 6 "Fair Value Measurements." Fair value may be estimated using comparable market data, a discounted cash flow method, or another method as discussed below. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of applicable sales estimates, operational costs and a risk-adjusted discount rate. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. Fair value of MCCS' inventory acquired was determined based on a comparative sales approach. Fair value for intangible assets acquired was primarily determined using a discounted cash flow model or multi-period excess earnings model under the income approach, which factors in discount rates, probability factors and forecasts. The fair values of property, plant and equipment acquired were primarily based on a cost approach using an indirect cost methodology to determine replacement cost. The inputs, as noted above, used to determine fair value required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Carrying value for current assets and liabilities acquired is typically representative of fair value due to their short term nature.

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

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, net of purchase price adjustments, is as follows (in thousands):

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

__________

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

(2) The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period. Based on actual production levels for the specified period or the nine months ended September 30, 2014, no additional consideration was due to CEU.

MCCS Acquisition. On June 26, 2014, we exercised the option granted in connection with the acquisition of MCE in November 2013 to acquire 100% of the equity interest in MCCS, an oilfield services company that specializes in providing services, primarily installation and pressure testing, to oil and natural gas exploration and production companies (the "MCCS Acquisition").

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

Consideration:
Fair value of common units granted (1)	$	789
Contingent consideration (2)	4,057
Noncontrolling interest (3)	831
Total fair value of consideration	$	5,677

__________

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

(2) The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 12 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.

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

12

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	109
Accounts receivable	524
Inventory	2,035
Other current assets	14
Property and equipment	107
Intangible asset (1)	1,700
Goodwill (2)	3,382
Other assets	28
Total assets acquired	7,899
Accounts payable and accrued liabilities	(1,431		)
Long-term debt	(791		)
Total liabilities assumed	(2,222		)
Net assets acquired	$	5,677

__________

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

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

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

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

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

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

__________

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

13

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

(2) The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 7 "Equity" for additional discussion of phantom units.

(3) The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ending December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 12 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value, net of any purchase price adjustments (in thousands):

Fair value of assets acquired and liabilities assumed:
Cash	$	1,668
Accounts receivable	22,674
Other current assets	620
Property and equipment	43,853
Intangible assets (1)	68,700
Goodwill (2)	14,224
Total assets acquired	151,739
Accounts payable and accrued liabilities	(5,937		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,577		)
Net assets acquired	$	113,162

__________

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

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

Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the three months ended March 31, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the three months ended March 31, 2014 have been prepared by adjusting the historical results of the Partnership to include the historical results of the 2014 Material Acquisitions through the dates of acquisition and estimates of the effect of these transactions on the combined results. In addition, pro forma adjustments have been made assuming the units issued as consideration for these acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund the Services Acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

14

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

	Three Months Ended March 31, 2014
	(in thousands, except per unit amounts)
Revenue	$	60,285
Net income attributable to New Source Energy Partners L.P.	$	2,107
Net income per common unit:
Basic	$	0.13
Diluted	$	0.13

The amount of revenues and revenues in excess of direct operating expenses included in the accompanying unaudited condensed consolidated statements of operations for the three months ended March 31, 2014 generated by the oil and natural gas properties acquired in the CEU Acquisition are shown in the table below. Direct operating expenses include lease operating expenses and production and other taxes and do not reflect certain expenses, such as general and administrative; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.

		Three Months Ended March 31, 2014
	(in thousands)
Revenue		$	1,883
Excess of revenue over direct operating expenses		$	1,119

3.  Debt

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

	March 31, 2015		December 31, 2014
Credit facility	$	84,000	$	83,000
Notes payable	19,652		20,424
Line of credit	3,429		3,619
Total debt	107,081		107,043
Less: current maturities of long-term debt	12,277		11,825
Long-term debt	$	94,804	$	95,218

Senior Secured Revolving Credit Facility

The Partnership has a senior secured revolving credit facility (the "credit facility") that is available to be drawn on subject to limitations based on its terms and certain financial covenants described below. As of March 31, 2015, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of its subsidiaries. The credit facility matures in February 2017.

15

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Additionally, the credit facility contains various covenants and restrictive provisions that, among other things, limit the ability of the Partnership to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. Notwithstanding the foregoing, the credit facility permits the Partnership to make distributions to its common unit holders in an amount not to exceed "available cash" (as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership) if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed 90%. As of March 31, 2015, the Partnership was in compliance with all covenants under the credit facility.

Our credit facility is subject to a borrowing base which is generally set by the bank semi-annually on April 1 and October 1 of each year. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. At March 31, 2015, the borrowing base under the credit facility was $90.0 million. In April 2015, our borrowing base was decreased from $90.0 million to $84.0 million and the semi-annual redetermination was moved to May 2015. On May 8, 2015, the borrowing base was reduced to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. As outstanding borrowings under our credit facility exceeded the new borrowing base resulting from the redetermination, we are required to eliminate this excess. On May 8, 2015, the Partnership remitted payment of $41.0 million which resulted in an outstanding balance under our credit facility of $43.0 million.

See Note 14 "Subsequent Events" for additional discussion of amendments to our credit facility agreement.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At March 31, 2015 and December 31, 2014, the average annual interest rate on borrowings outstanding under the credit facility was 3.51% and 3.44%, respectively.

Notes Payable

MCES Notes Payable. The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. The notes range from 12 to 60 months in duration with maturity dates from August 2015 through March 2019 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. The Partnership had $6.5 million outstanding, of which $3.2 million was current, under the MCES notes payable as of March 31, 2015.

EFS Loan Agreement. In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on EFS' existing notes payable, which were originally set to mature on June 26, 2015. In March 2015, we refinanced EFS' notes payable to extend the maturity date to March 2018. The balance on the note payable at March 31, 2015 was $11.7 million, of which $4.2 million was current.

The note payable has a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at March 31, 2015, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The note payable is collateralized by various assets of the parties to the agreement and guaranteed by MCE. The Partnership is required to maintain a reserve bank account into which $0.3 million shall be deposited quarterly beginning after the initial deposit of $0.5 million on September 30, 2015, and used to fund an additional annual payment on September 30th of each year during the term of the note.

The EFS loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0, (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $1.0 million by June 30, 2015 increasing to at least $3.5 million by October 1, 2015, in each case as more fully described in the loan agreement. As of March 31, 2015, EFS and RPS were in compliance with the covenants under the loan agreement.

16

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

MCES Promissory Notes. On January 9, 2015 and February 24, 2015, MCES issued promissory notes totaling approximately $1.4 million, to acquire land from entities owned 50% by Mr. Kos, Chief Executive Officer of our general partner, and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner. Both promissory notes bear interest at prime plus one percent and are payable, including all accrued interest, on December 31, 2015. No payments are due prior to maturity. See Note 9 "Related Party Transactions" for additional discussion of the related party land transactions.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. Interest only payments are due monthly with the line of credit which was set to mature in May 2015, but was extended to mature in June 2015. Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at March 31, 2015. The line of credit is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. Based on the outstanding balance of $3.4 million, there was $0.6 million of available borrowing capacity at March 31, 2015.

The line of credit contains a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of March 31, 2015, MCES was in compliance with this covenant under the line of credit.

4.  Factoring Payable

The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of MCES. The outstanding balance was paid and the agreement was terminated in February 2014 when MCES established its line of credit. See Note 3 "Debt" for discussion of MCES' line of credit.

In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 3% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not collected within 90 days, the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $11.4 million as of March 31, 2015.

5.  Derivative Contracts 

 Due to the volatility of commodity prices, the Partnership periodically enters into derivative contracts for a portion of its oil, natural gas and NGL production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of derivative contracts limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and NGLs, it also reduces the Partnership’s potential exposure to adverse price movements. The Partnership’s derivative contracts apply to only a portion of its expected production, provide only partial price protection against declines in market prices and limit the Partnership’s potential gains from future increases in market prices. Changes in the derivatives' fair values are recognized in earnings since the Partnership has elected not to designate its derivative contracts as hedges for accounting purposes.

17

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

At March 31, 2015, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

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

The following tables present our derivative instruments outstanding as of March 31, 2015:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2015	30,072	$	80.00	$	93.25

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	27,500	$	77.50	$	92.50	$	102.60

Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	30,080	$	88.90
2016	36,658	$	86.00

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2015	976,356	$	4.00	$	4.32

Natural gas put options	Volumes (MMBtu)	Floor Price
2015	620,040	$	3.50
2016	930,468	$	3.50

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2015	582,451	$	4.25
2016	629,301	$	4.37

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	62,213	$	75.18

18

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

March 31, 2015	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset		Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	7,292	$	—	$	7,292
Commodity derivatives - long-term assets	1,659		—		1,659
Total	$	8,951	$	—	$	8,951
Liabilities:
Commodity derivatives - current liabilities	$	—	$	—	$	—
Commodity derivatives - long-term liabilities	—		—		—
Total	$	—	$	—	$	—

December 31, 2014	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	8,309	$	(61	)	$	8,248
Commodity derivatives - long-term assets	1,818		—			1,818
Total	$	10,127	$	(61	)	$	10,066
Liabilities:
Commodity derivatives - current liabilities	$	61	$	(61	)	$	—
Commodity derivatives - long-term liabilities	—		—			—
Total	$	61	$	(61	)	$	—

See Note 6 "Fair Value Measurements" for additional information on the fair value measurement of the Partnership's derivative contracts.

The following table presents gain (loss) on our derivative contracts as included in the accompanying unaudited statements of operations for the three months ended March 31, 2015 and 2014 (in thousands):

	Three Months Ended March 31,
	2015		2014
Total gain (loss) on derivative contracts, net (1)	$	1,224	$	(3,132	)

__________

(1) Included in gain (loss) on derivative contracts for the three months ended March 31, 2015 and 2014 are net cash receipts (payments) upon contract settlement of $2.3 million and $(2.4) million, respectively.

19

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

6.  Fair Value Measurements

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

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

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

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

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

Level 2 Fair Value Measurements

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

Level 3 Fair Value Measurements

Derivative contracts. The fair values of our natural gas collars, natural gas and NGL put options and NGL fixed price swaps at March 31, 2014 were based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness. The significant unobservable inputs used in the fair value measurement of our natural gas and NGL put options and NGL fixed price swaps were the estimated probability of exercise and the estimate of NGL futures prices. Significant increases (decreases) in the probability of exercise and NGL futures prices could result in a significantly higher (lower) fair value measurement. 

Contingent consideration. As discussed in Note 12 "Commitments and Contingencies," the Partnership agreed to pay additional consideration on certain acquisitions if specific target metrics are met. The fair value of the contingent consideration resulting from these acquisitions is based on the present value of estimated future payments, using various inputs, including forecasted EBITDA metrics and the probability that targets for additional payout will be met. Significant increases (decreases) in the probability of meeting target payout levels could result in a significantly higher (lower) fair value measurement. 

20

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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):

March 31, 2015	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total Carrying Value
Oil and natural gas collars	$	—	$	2,436	$	—	$	2,436
Oil, natural gas and NGL put options	—		1,035		—		1,035
Oil, natural gas and NGL fixed price swaps	—		5,480		—		5,480
Total	$	—	$	8,951	$	—	$	8,951

December 31, 2014	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)		Unobservable Inputs (Level 3)			Total Carrying Value
Oil and natural gas collars	$	—	$	2,411	$	—		$	2,411
Oil, natural gas and NGL put options	—		1,405		—			1,405
Oil, natural gas and NGL fixed price swaps	—		6,250		—			6,250
Contingent consideration	—		—		(23,330		)	(23,330		)
Total	$	—	$	10,066	$	(23,330	)	$	(13,264	)

The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the three months ended March 31, 2014 (in thousands):

	Three Months Ended March 31, 2014
Beginning balance	$	(2,517	)
Loss on derivative contracts	(2,432		)
Cash paid upon settlement	2,106
Ending balance (1)	$	(2,843	)
Unrealized losses included in earnings relating to derivatives held at period end	$	(702	)

__________

(1) Fair values related to the Company’s natural gas collars, natural gas and NGL put options and NGL fixed price swaps were transferred from Level 3 to Level 2 in the second quarter of 2014 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. 

See Note 5 "Derivative Contracts" for additional discussion of our derivative contracts.

Fair Value of Financial Instruments

Credit Facility. The carrying amount of the credit facility of $84.0 million and $83.0 million as of March 31, 2015 and December 31, 2014, respectively, approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings.

Notes Payable. The carrying value of our notes payable of $19.7 million and $20.4 million at March 31, 2015 and December 31, 2014 approximated fair value based on rates applicable to similar instruments. 

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

21

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Fair Value on a Non-Recurring Basis

The Partnership performs valuations on a non-recurring basis primarily as it relates to the consideration, assets acquired, and liabilities assumed related to acquisitions. See Note 2 "Acquisitions" and Note 12 "Commitments and Contingencies" for discussion of these valuations.

7.  Equity

Equity Offerings

Issuance for Acquisitions. In 2014, we issued 1,964,957 of common units to satisfy the equity portion of the consideration paid in the CEU Acquisition, the MCCS Acquisition, and the Services Acquisition. See Note 2 "Acquisitions" for additional discussion of these transactions.

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

Distributions

Distributions are declared and distributed within 45 days following the end of each quarter. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the three months ended March 31, 2015 and 2014, as shown in the following table (in thousands):

Distributions	Payable Date	Distribution per Unit		Common Units		Subordinated Units		General Partner Units		Total
2015
First Quarter	May 15, 2015	$	0.20	$	3,312	$	—	$	—	$	3,312
2014
First Quarter	May 15, 2014	$	0.580	$	7,852	$	1,279	$	90	$	9,221

Pursuant to our partnership agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. No such incentive distributions were made to our general partner as quarterly distributions declared by the board of directors for the first quarters of 2015 and 2014 did not exceed the specified targets. The distribution per common unit of $0.20 in the first quarter of 2015 is below the minimum quarterly distribution ("MQD") per the partnership agreement before the subordinated units receive distributions. Additionally, the subordinated units are not entitled to receive distributions until the common units receive an amount equal to the MQD and the cumulative arrearages which is approximately $5.3 million at March 31, 2015. The subordination period ends on the first business day after all units have received the MQD for each of four consecutive quarters ending on or after December 31, 2015, or as otherwise provided for under the partnership agreement.

See Note 14 "Subsequent Events" for discussion of distribution declared in May 2015.

22

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Noncontrolling Interest

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

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

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

No distributions were due to the MCE Class B unitholders for the first quarter of 2015 or 2014.

Equity Compensation

We may grant awards of the Partnership's common units to employees under the Partnership's Long-Term Incentive Plan ("LTIP") or Fair Market Value Purchase Plan ("FMVPP"). In the first quarter of 2015, we granted 242,753 common units under the LTIP. Of these common units granted, 219,439 vested immediately or had accelerated vesting, which resulted in $1.5 million of equity-based compensation expense during the three months ended March 31, 2015.

Phantom Units. In conjunction with the Services Acquisition, the Partnership granted 432,038 phantom units, which represent the right to receive common units or cash equal to the value of the associated common units, to employees of EFS and RPS under the FMVPP. The phantom units vest over a period not to exceed 2 years. Although the phantom unit grants may be settled in either common units or cash at the holder's election, the settlement of the phantom units upon vesting will be made from a transfer or sale of the associated common units that were issued to an escrow account, reflected as contra equity on the accompanying unaudited condensed consolidated balance sheet, in conjunction with the Services Acquisition. As a result, the 401,171 phantom units valued at $10.1 million with a service requirement were measured at fair market value of the Partnership’s common units on the grant date and are being expensed over the vesting period in accordance with accounting guidance for equity compensation. In the first quarter of 2015, $2.3 million was expensed for these phantom units, including $0.9 million related to accelerated phantom unit vesting.

For the three months ended March 31, 2015 and 2014, the Partnership recorded total equity-based compensation expense of $3.9 million and $0.3 million, respectively.

8. 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.

23

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

We present earnings per unit regardless of whether such earnings would or could be distributed under the terms of our partnership agreement. Accordingly, the reported earnings per unit is not indicative of potential cash distributions that may be made based on historical or future earnings. Basic and diluted net income per unit is calculated by dividing net income attributable to each class of unit by the weighted average number of units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. During the three months ended March 31, 2015, LTIP awards of 32,542 common units were excluded from the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of March 31, 2014. Therefore, basic and diluted earnings per unit are the same for the three months ended March 31, 2014.

Basic and diluted earnings per unit for the three months ended March 31, 2015 and 2014 were computed as follows (in thousands, except per unit amounts):

	Three Months Ended   March 31, 2015
	Common Units			Subordinated Units			General Partner
Net loss	$	(49,574	)	$	(7,128	)	$	(470	)
Weighted average units outstanding	16,346			2,205			155
Basic and diluted loss per unit	$	(3.03	)	$	(3.23	)	$	(3.03	)

	Three Months Ended   March 31, 2014
	Common Units			Subordinated Units			General Partner
Net loss	$	(1,241	)	$	(271	)	$	(19	)
Weighted average units outstanding	9,920			2,205			155
Basic and diluted loss per unit	$	(0.12	)	$	(0.12	)	$	(0.12	)

9. Related Party Transactions

Ownership. The Partnership is controlled by our general partner. As of March 31, 2015, our general partner was owned 69.4% by Kristian Kos, the Chairman and Chief Executive Officer of our general partner, and 25.0% by David J. Chernicky, the former Chairman of the board of directors of our general partner. Mr. Kos beneficially owns approximately 5.0% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through Deylau, LLC ("Deylau"), an entity he controls. As of March 31, 2015, Mr. Chernicky beneficially owned approximately 15.6% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through NSEC and Scintilla, entities that he controls. In addition, Mr. Chernicky beneficially owns 100% of the 2,205,000 subordinated units through his control of NSEC. As a result of Mr. Chernicky's ownership of the Partnership and his ownership of all of the membership interests in New Dominion, which operates all of the Partnership's oil and natural gas properties, transactions with New Dominion are deemed to be with a related party. See Note 14 "Subsequent Events" for discussion of the transfer of interest in our general partner in April 2015.

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

New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated was approximately $0.2 million as of March 31, 2015 and $0.4 million as of December 31, 2014, all of which is classified as a long-term liability in the accompanying unaudited condensed consolidated balance sheets. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.

24

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three months ended March 31, 2015 and 2014 (in thousands):

	Three Months Ended March 31,
	2015		2014
Producing overhead and supervision charges	$	733	$	375
Drilling and completion supervision charges	38		9
Saltwater disposal fees	244		415
Total expenses incurred	$	1,015	$	799

Receivables from New Dominion represent amounts due primarily for sale of our oil, natural gas and NGL production. Payables due to New Dominion represent amounts owed primarily for production costs associated with production of our oil, natural gas and NGL volumes. At March 31, 2015 and December 31, 2014, the Partnership had related party receivables, net from New Dominion of $4.4 million and $3.4 million, respectively.

New Source Energy GP, LLC. Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three months ended March 31, 2015 and 2014, the amount paid to our general partner for such reimbursements was approximately $0.03 million and $0.3 million, respectively, and was included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations. At March 31, 2015 and December 31, 2014, $0.2 million and $2.3 million, respectively, were due to our general partner for reimbursement and included in accounts payable - related party in the accompanying unaudited condensed consolidated balance sheets.

Transactions with Chief Financial Officer. The Partnership engaged Finley & Cook, PLLC ("Finley & Cook") to provide various accounting services on our behalf during the three months ended March 31, 2015 and 2014. Richard Finley, the Chief Financial Officer of our general partner, was an equity member of Finley & Cook until October 2014, holding a 31.5% ownership interest. As Mr. Finley has subsequently continued in an advisory capacity with Finley & Cook, accounting services received from Finley & Cook during the first quarter of 2015 are included as related party transactions. The Partnership paid Finley & Cook approximately $0.1 million in fees for each of the three months ended March 31, 2015 and 2014.

Acquisitions. In June 2014, we exercised our option to acquire MCCS, which was owned by Mr. Kos and Mr. Tourian. See Note 2 "Acquisitions" for discussion of this acquisition and Note 12 "Commitments and Contingencies" for discussion of the MCCS Contingent Consideration. As part of the acquisition of MCCS, we assumed a payable to an entity owned by Mr. Kos and Mr. Tourian. The resulting $0.7 million related party payable was paid as of December 31, 2014.

On January 9, 2015, MCES acquired two separate parcels of land, one located in Canadian County, Oklahoma and one located in Ector County, Texas, from an entity owned 50% by Mr. Kos and 50% by Mr. Tourian for approximately $0.9 million. Additionally, on February 24, 2015, MCES acquired land located in Karnes County, Texas from an entity owned 67% by Mr. Kos and 33% by Mr. Tourian for approximately $0.5 million. The purchase price for each transaction was determined based on independent third-party appraisals for each property. In each transaction, a promissory note for the entire purchase price was issued by MCES to Mr. Kos and Mr. Tourian and is payable on December 31, 2015.

Since the Chairman and Chief Executive Officer of our general partner, Kristian B. Kos, through his control of our general partner, is deemed to control the Partnership and also controls the entities that sold MCES land, the portion of the land acquired from Mr. Kos was recorded at his carrying value, which totaled $0.6 million for the three parcels of land at the time of acquisition. The difference between Mr. Kos' carrying value and the purchase price was reflected in equity.

See Note 3 "Debt" for additional discussion on these notes payable.

25

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

10. Property, Plant and Equipment

Oil and Natural Gas Properties. We use the full cost method to account for our oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil and natural gas reserves are capitalized into a full cost pool. These capitalized costs include costs of all unproved properties, internal costs directly related to our acquisition and exploration and development activities.

Under the full cost method of accounting, the net book value of oil and natural gas, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the discounted estimated after-tax future net revenue from proved oil and natural gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and natural gas, plus the cost of properties not subject to amortization. In calculating future net revenues, prices and costs used are based on the most recent 12-month average. The Company has entered into various commodity derivative contracts; however, these derivative contracts are not accounted for as cash flow hedges. The net book value, less related deferred tax liabilities, is compared to the ceiling limitation on a quarterly and annual basis. Any excess of the net book value, less related deferred taxes, is written off as an expense. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling limitation in the subsequent period.

Based on the 12-month average prices of oil, natural gas and NGLs as of March, 31, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015. Continued low levels or further declines in oil, natural gas and NGL prices subsequent to March 31, 2015 are expected to result in additional ceiling test write downs in the second quarter of 2015 and in subsequent periods. The amount of any future impairment is difficult to predict, and will primarily depend on oil, natural gas and NGL prices during these periods.

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

	March 31, 2015			December 31, 2014
Vehicles and transportation equipment	$	16,165		$	15,891
Machinery and equipment	47,717			44,441
Office furniture and equipment	1,518			1,069
Iron	13,390			12,258
Total	78,790			73,659
Less: accumulated depreciation	(7,247		)	(4,773		)
	71,543			68,886
Land	1,201			—
Property and equipment, net	$	72,744		$	68,886

11.  Asset Retirement Obligations

A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2014 to March 31, 2015 is as follows (in thousands):

Asset retirement obligation at January 1, 2015	$	3,681
Liability incurred upon acquiring and drilling wells	—
Accretion	74
Asset retirement obligation at March 31, 2015	3,755
Less current portion	116
Asset retirement obligations, net of current	$	3,639

26

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

12. Commitments and Contingencies

Commitments

The Partnership is a party to various agreements under which it has rights and obligations to participate in the acquisition and development of undeveloped properties held and to be acquired by Scintilla and New Dominion. These properties will be held by New Dominion for the benefit of the Partnership pending development of the properties. The Partnership is required by its underlying agreements with New Dominion to pay certain acreage fees to reimburse New Dominion for the cost of the acreage attributable to the Partnership’s working interest when invoiced by New Dominion. The Partnership recognizes an asset and corresponding liability as the acreage costs are incurred by New Dominion. See Note 9 "Related Party Transactions." The agreements require us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. There are significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements. The agreements also require us to pay New Dominion our proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

New Dominion serves as the operator for all of our properties. The successful operation of our exploration and production business depends on continued utilization of New Dominion’s oil, natural gas, and NGL infrastructure and technical staff as the operator of our properties. Failure of New Dominion to perform its obligations could have a material adverse effect on our operations and our financial results.

Contingent Consideration

MCE. The former owners of MCE were entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE, excluding EFS, RPS and MCCS, for the trailing nine month period ending March 31, 2015, less certain adjustments and subject to a $120.0 million cap. The contingent consideration was valued at $6.3 million at the acquisition date and was included in the consideration for the MCE Acquisition. Based on actual results for MCE for the nine month period ending March 31, 2015, the MCE Contingent Consideration was deemed to have no value at March 31, 2015.

MCCS. The former owners of MCCS were entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $4.5 million cap. The contingent consideration was valued at $4.1 million at the acquisition date and was included in the consideration for the MCCS Acquisition. Based on actual results for MCCS for the nine month period ending March 31, 2015, the MCCS Contingent Consideration was deemed to have no value at March 31, 2015.

EFS/RPS. The former owners of EFS and RPS are entitled to receive additional consideration in the form of cash and common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments. The terms of the contribution agreement provide that the additional consideration is to be paid approximately 50% in cash and approximately 50% in common units, consistent with the initial consideration for the Services Acquisition. However, the former owners can elect to receive a larger portion of the payout in common units. The EFS/RPS Contingent Consideration was valued at $22.0 million as of the acquisition date and was included in the consideration for the Services Acquisition. The fair value of the EFS/RPS Contingent Consideration was $23.3 million as of December 31, 2014.

In March 2015, we entered into an agreement with the former owners that allows for the payment of the cash portion of the EFS/RPS Contingent Consideration to be extended to May 2016. Beginning in June 2015, interest payments are due monthly with principal and any unpaid interest due May 1, 2016. This agreement also restricts equity compensation and bonus payments to certain officers of the Partnership as well as the Partnership's ability to acquire another entity until this note has been paid. As a result, this portion of the EFS/RPS Contingent Consideration has been reflected as a long-term liability in the accompanying consolidated balance sheet as of March 31, 2015. Additionally, a receivable of approximately $1.0 million due from the former owners has been offset against the cash portion of the contingent consideration obligation.

27

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Legal Matters

On January 12, 2015, David J. Chernicky, the beneficial owner of approximately 30.6% of our general partner, approximately 15.6% of our common units and all of our subordinated units, and his affiliated entities, Scintilla, LLC, New Source Energy Corporation and New Dominion, LLC (collectively, “plaintiffs”) filed a lawsuit against the Partnership, our general partner and certain current officers of our general partner, including Chairman and Chief Executive Officer, Kristian Kos, and Chief Financial Officer, Richard Finley, and certain of their affiliated entities (collectively, “defendants”) in the District Court of Tulsa County, Oklahoma. The plaintiffs allege various claims against the defendants, including that plaintiffs did not receive fair value for various oil and natural gas working interests acquired from them by the Partnership. The plaintiffs also allege that the Partnership has been unjustly enriched and that the properties acquired from them by the Partnership pursuant to the transactions in question should be held in a constructive trust in favor of the plaintiffs. Additionally, the plaintiffs claim that the defendants have conspired to commit constructive fraud, breach of fiduciary duty, negligence and gross negligence against the plaintiffs. Additionally, the plaintiffs allege that the defendants have intentionally interfered with the defendants' current business arrangements with certain working interest owners in the properties the plaintiffs operate as well as future business opportunities. The plaintiffs also claim that the Partnership is wrongfully refusing to remove the restrictive legends on common units issued by the Partnership to the plaintiffs in private transactions in exchange for the oil and natural gas working interests described above.

On February 23, 2015, the defendants filed several motions to dismiss the claims raised in the plaintiffs’ petition, including motions by the Partnership and our general partner that (i) the defendants' claims fail to state a claim; (ii) the defendants' claims are time barred by statues of limitations; and (iii) Tulsa County is an improper venue. A hearing on the motions to dismiss is currently scheduled to be held on May 26, 2015. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action.

In addition to the proceeding described above, on January 29, 2015, the Partnership received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by the Partnership to NSEC. The total amount of the purported claims totaled approximately $1.9 million. In 2015, New Dominion has withheld all revenue from the Partnership's sold oil and natural gas production in satisfaction of these claims as well as other amounts that the Partnership has disputed. As with the proceeding described above, the Partnership intends to pursue this matter vigorously and believes the claims are without any substantial merit. The Partnership has not established any reserves relating to this action.

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

In the case of Mattingly v. Equal Energy, LLC, New Dominion is a named defendant. In this case, the plaintiffs assert claims on behalf of a class of royalty owners in wells operated by New Dominion and others from which natural gas is sold by New Dominion to Scissortail Energy, LLC ("Scissortail"). The plaintiffs assert that royalties to the class should be paid based upon the price received by Scissortail for the natural gas and its components at the tailgate of the plant, rather than the price paid by Scissortail at the wellhead where the natural gas is purchased. The plaintiffs assert a variety of breach of contract and tort claims. A hearing on the matter was held in August 2014 at which Scissortail’s motion to dismiss was granted with prejudice and New Dominion’s motion to dismiss was granted in part. The plaintiffs have appealed the court's granting of the dismissal. In January, the appeal was assigned to the Court of Civil Appeals in Tulsa, Oklahoma. A class certification hearing has also been set for November 2015.

Any liability on the part of New Dominion, as contract operator, would be allocated to the working interest owners to pay their proportionate share of such liability. While the outcome and impact on the Partnership of this proceeding cannot be predicted with certainty, management believes a loss of up to $250,000 may be reasonably possible. Due to the uncertainty, no reserve has been established for this matter.

The Partnership may be involved in other various routine legal proceedings incidental to its business from time to time. While the results of litigation and claims cannot be predicted with certainty, the Partnership believes the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, the Partnership believes the probable final outcome of such matters will not have a material adverse effect on the Partnership's consolidated financial position, results of operations, cash flow or liquidity.

28

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

13. Business Segment Information

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

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

	Exploration and Production			Oilfield Services			Total
Three Months Ended March 31, 2015
Revenues	$	6,567		$	31,550		$	38,117
Direct operating expenses	4,366			23,059			27,425
Segment margin	$	2,201		$	8,491		$	10,692
Depreciation, depletion, amortization and accretion	4,794			7,627			12,421
Impairment of oil and natural gas properties	43,119			—			43,119
General and administrative expenses	4,569			7,665			12,234
Loss from operations	$	(50,281	)	$	(6,801	)	$	(57,082	)
Capital expenditures (1)	$	1,014		$	6,103		$	7,117
At March 31, 2015
Total assets (2)	$	149,200		$	166,333		$	315,533
Three Months Ended March 31, 2014
Revenues	$	18,851		$	8,576		$	27,427
Direct operating expenses	5,382			4,566			9,948
Segment margin	$	13,469		$	4,010		$	17,479
Depreciation, depletion, amortization and accretion	5,887			3,460			9,347
General and administrative expenses	3,843			1,717			5,560
Income (loss) from operations	$	3,739		$	(1,167	)	$	2,572
Capital expenditures (1)	$	10,072		$	3,143		$	13,215
At December 31, 2014
Total assets	$	199,178		$	176,368		$	375,546

__________

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

(2) Exploration and Production includes impairment of oil and natural gas properties of $43.1 million as discussed in Note 10 "Property, Plant and Equipment."

Exploration and Production Oilfield Services (1) Total

29

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

14.  Subsequent Events

Ownership of Our General Partner. On April 27, 2015, the Partnership entered into a purchase agreement among the Partnership for certain limited purposes, Deylau and 2100 Energy LLC (“2100 Energy”). Prior to the consummation of the transactions contemplated by the Purchase Agreement, Deylau, owned 69.4% of the limited liability company interest in our general partner.

Pursuant to the purchase agreement, (i) Deylau made an initial transfer of 26.5% of its limited liability company interest in our general partner (which constitutes an 18.4% limited liability company interest in our general partner) to 2100 Energy (the “Initial Transfer”), and (ii) following the Initial Transfer and the satisfaction of various conditions (including 2100 Energy causing one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, sell $150 million of oil and natural gas assets to a subsidiary of the Partnership), (A) Deylau will transfer its remaining limited liability company interest in our general partner (which constitutes a 51.0% limited liability company interest in our general partner) to 2100 Energy and (B) the Partnership will transfer all of its limited liability company interest in MCE GP, the general partner of MCLP, to an entity owned, directly or indirectly, by Deylau and Signature Investments LLC, which is wholly-owned by Mr. Tourian. Following such transactions, the Partnership will still own all of the equity interests in MCLP except for the general partner interest and the Class B units.

Exchange Agreement. On April 27, 2015, the Partnership entered into an exchange agreement with our general partner (the “Exchange Agreement”). Pursuant to the Exchange Agreement, our general partner eliminated the economic portion of its general partner interest in the Partnership and canceled all of its general partner units in exchange for the issuance by the Partnership of an equivalent amount of 155,102 common units, which were subsequently distributed to the members of our general partner pro rata in accordance with their ownership interest. The general partner interest ceased to be an economic interest in the Partnership; however, our general partner continues to be the general partner of the Partnership.

Amendments to Credit Agreement. On April 27, 2015, we entered into a Seventh Amendment (the "Seventh Amendment")to our credit agreement governing our credit facility, which, among other things, (i) amends the Change in Control definition to provide for 2100 Energy’s acquisition of Deylau’s limited liability company interest in our general partner, (ii) increased certain of the collateral requirements, (iii) granted the Partnership the ability to make certain cash distributions to the holders of the Partnership's common units that are not otherwise permitted by the credit agreement and (iv) permits us to dispose all of our limited liability company interest in MCE GP upon the satisfaction of various conditions (including 2100 Energy causing one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, transfer $150 million of oil and natural gas assets to a subsidiary of us) as described above. On May 1, 2015, we entered into an Eighth Amendment (the "Eighth Amendment") to the credit agreement governing our credit facility. The Eighth Amendment (i) permits the Partnership to make cash distributions up to $6.0 million per year to holders of our Series A Preferred Units, (ii) amends the terms of a consent letter dated April 8, 2015 ("Consent Letter"), by and among the Partnership, Bank of Montreal and the other lenders party to the credit agreement, to postpone the redetermination of the borrowing base under our credit facility until May 8, 2015, (iii) makes null and void the waiver contained in the Seventh Amendment to the credit agreement permitting the Partnership to make certain cash distributions to the holders of the Partnership's common units that are not otherwise permitted by the credit agreement and (iv) imposes certain hedging requirements for our oil and natural gas assets if the Partnership unwinds any current hedges prior to the October 2015 redetermination date. As a result of the Eighth Amendment, distributions to common unitholders are not permitted unless the amount outstanding is 90% or less of the current borrowing base.

30

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Preferred Units Offering.  On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. The Series A Preferred Units are cumulative convertible preferred units that are entitled to receive quarterly cash distributions at the rate of 11.00% per annum. The Series A Preferred Units are convertible into our common units on any January 1, April 1, July 1 or October 1 by the holder and we may elect to convert the Series A Preferred Units into our common units on or after July 15, 2018 in certain circumstances. The initial conversion rate for the Series A Preferred Units is 3.7821 common units per Series A Preferred Unit and they are mandatorily redeemable by the holder on or after July 15, 2022. We will redeem all of the Series A Preferred on July 15, 2022 at a redemption price equal to the liquidation preference of $25.00 plus an amount equal to accumulated but unpaid distributions thereon. If we do not redeem the Series A Preferred Units on July 15, 2022, then the per annum distribution rate will increase by an additional 2.00% per month until such redemption, up to a maximum rate per annum of 20.00%.

We received net proceeds of approximately $40.4 million from this offering after deducting underwriting discounts of $2.6 million and estimated offering costs of $1.0 million.  We used all of the net proceeds from the offering to repay a portion of the indebtedness outstanding under our credit facility. The Partnership has granted the underwriters a 30-day option to purchase up to 264,000 additional Series A Preferred Units. 

Distributions.On May 8, 2015, the Partnership declared quarterly distributions of $0.20 per unit to unitholders of record, including holders of common units for the three months ended March 31, 2015. The following distributions will be paid on May 15, 2015 to holders of record as of the close of business on May 11, 2015 (in thousands):

	Common Units		Subordinated Units		General Partner Units		Total
Distributions	$	3,312	$	—	$	—	$	3,312

31

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 2014 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 months ended March 31, 2015 and 2014, 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 and in "Item 1A. Risk Factors" of the 2014 Form 10-K. 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 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 Delaware limited partnership formed in October 2012 to own and acquire oil and natural gas properties in the United States. We are engaged in the 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, we are engaged in oilfield services through our oilfield services subsidiaries. Our oilfield services business provides essential wellsite services during drilling and completion stages of a well, including full service blowout prevention installation, pressure testing services, including certain ancillary equipment necessary to perform such services, well testing and flowback services to companies in the oil and natural gas industry primarily in Oklahoma, Texas, New Mexico, Kansas, Pennsylvania, Ohio and West Virginia.

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.

How We Evaluate Our Operations

We use certain financial and operational metrics to assess the specific performance of our oil and natural gas operations and our oilfield services operations.

Oil and Natural Gas Operations

• produced volumes;

• realized prices on the sale of oil, natural gas, and NGLs;

• lease operating expenses; and

• production taxes.

32

Oilfield Services Operations

• revenue; and

• costs of providing oilfield services.

Adjusted EBITDA

We also utilize Adjusted EBITDA to monitor our performance. We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, non-cash compensation expense, non-recurring transaction fees, 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 (loss) 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.

Recent Developments

Ownership of Our General Partner. On April 27, 2015, the Partnership entered into a purchase agreement among the Partnership for certain limited purposes, Deylau and 2100 Energy LLC (“2100 Energy”). Prior to the consummation of the transactions contemplated by the Purchase Agreement, Deylau, owned 69.4% of the limited liability company interest in our general partner.

Pursuant to the purchase agreement, (i) Deylau made an initial transfer of 26.5% of its limited liability company interest in our general partner (which constitutes an 18.4% limited liability company interest in our general partner) to 2100 Energy (the “Initial Transfer”), and (ii) following the Initial Transfer and the satisfaction of various conditions (including 2100 Energy causing one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, sell $150 million of oil and natural gas assets to a subsidiary of the Partnership), (A) Deylau will transfer its remaining limited liability company interest in our general partner (which constitutes a 51.0% limited liability company interest in our general partner) to 2100 Energy and (B) the Partnership will transfer all of its limited liability company interest in MCE GP, the general partner of MCLP, to an entity owned, directly or indirectly, by Deylau and Signature Investments LLC, which is wholly-owned by Mr. Tourian, our President and Chief Operating Officer. Following such transactions, the Partnership will still own all of the equity interests in MCLP except for the general partner interest and the Class B units.

Exchange Agreement. On April 27, 2015, the Partnership entered into an exchange agreement with our general partner (the “Exchange Agreement”). Pursuant to the Exchange Agreement, our general partner eliminated the economic portion of its general partner interest in the Partnership and canceled all of its general partner units in exchange for the issuance by the Partnership of an equivalent amount of 155,102 common units, which were subsequently distributed to the members of our general partner pro rata in accordance with their ownership interest. The general partner interest ceased to be an economic interest in the Partnership; however, our general partner continues to be the general partner of the Partnership.

33

Amendments to Credit Agreement. On April 27, 2015, we entered into a Seventh Amendment (the "Seventh Amendment")to our credit agreement governing our credit facility, which, among other things, (i) amends the Change in Control definition to provide for 2100 Energy’s acquisition of Deylau’s limited liability company interest in our general partner, (ii) increased certain of the collateral requirements, (iii) granted the Partnership the ability to make certain cash distributions to the holders of the Partnership's common units that are not otherwise permitted by the credit agreement and (iv) permits us to dispose all of our limited liability company interest in MCE GP upon the satisfaction of various conditions (including 2100 Energy causing one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, transfer a $150 million of oil and natural gas assets to a subsidiary of us) as described above . On May 1, 2015, we entered into an Eighth Amendment (the "Eighth Amendment") to the credit agreement governing our credit facility. The Eighth Amendment (i) permits the Partnership to make cash distributions up to $6.0 million per year to holders of our 11.00% Series A Cumulative Convertible Preferred Units ("Series A Preferred Units"), (ii) amends the terms of a consent letter dated April 8, 2015 ("Consent Letter"), by and among the Partnership, Bank of Montreal and the other lenders party to the credit agreement, to postpone the redetermination of the borrowing base under our credit facility until May 8, 2015, (iii) makes null and void the waiver contained in the Seventh Amendment to the credit agreement permitting the Partnership to make certain cash distributions to the holders of the Partnership's common units that are not otherwise permitted by the credit agreement and (iv) imposes certain hedging requirements for our oil and natural gas assets if the Partnership unwinds any current hedges prior to the October 2015 redetermination date. As a result of the Eighth Amendment, distributions to common unitholders are not permitted unless the amount outstanding is 90% or less of the current borrowing base.

Preferred Units Offering.  On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. The Series A Preferred Units are cumulative convertible preferred units that are entitled to receive quarterly cash distributions at the rate of 11.00% per annum. The Series A Preferred Units are convertible into our common units on any January 1, April 1, July 1 or October 1 by the holder and we may elect to convert the Series A Preferred Units into our common units on or after July 15, 2018 in certain circumstances. The initial conversion rate for the Series A Preferred Units is 3.7821 common units per Series A Preferred Unit and mandatorily redeemable by the holder on or after July 15, 2022. We will redeem all of the Series A Preferred on July 15, 2022 at a redemption price equal to the liquidation preference of $25.00 plus an amount equal to accumulated but unpaid distributions thereon. If we do not redeem the Series A Preferred Units on July 15, 2022, then the per annum distribution rate will increase by an additional 2.00% per month until such redemption, up to a maximum rate per annum of 20.00%.

We received net proceeds of approximately $40.4 million from this offering after deducting underwriting discounts of $2.6 million and estimated offering costs of $1.0 million.  We used all of the net proceeds from the offering to repay a portion of the indebtedness outstanding under our credit facility. The Partnership has granted the underwriters a 30-day option to purchase up to 264,000 additional Series A Preferred Units. 

Outlook

Exploration and Production. As our revenue, earnings and cash flow are 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 have historically been volatile and recent oil prices have declined from those 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. Our derivative arrangements serve to mitigate a portion of the effect of this price volatility on our exploration and production cash flows. We will need to incur capital expenditures in 2015 to maintain production levels, develop our reserves and maintain our oilfield services equipment; however, such capital expenditures are dependent on commodity prices, availability under debt instruments and proceeds from equity issuances, along with cash flows from operating activities.

Oil, natural gas, and NGL prices have historically been volatile based on supply and demand dynamics. Factors that can affect the demand for our production include domestic and international economic conditions, the market price and demand for energy, the cost to develop oil and natural gas reserves in the United States, along with state and federal regulation. During the fourth quarter of 2014 and continuing into 2015, significant declines in the price of oil, natural gas and NGLs have made it necessary for us to reduce our exploration and development activities, reduce our budget for capital expenditures, and focus on prudent cost reduction efforts.

34

As an oil, natural gas, and NGL producer, we face the challenge of natural production declines, volatile commodity prices and, as a non-operated working interest owner, operating expenses imposed by our contract operator. As initial reservoir pressures are depleted, oil, natural gas, and NGL production from a given well or formation decreases. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel. Our future drilling plans are dependent on commodity prices. If commodity prices remain low or decline further in 2015, our ability to drill economic wells will be curtailed. Based on current commodity prices, we do not anticipate drilling any new wells in 2015.

Although we monitor our costs and work with our contract operator to actively manage our expenses, we have seen a significant rise in our lease operating expenses in 2014, which continued in the first quarter of 2015, compared to previous years and expect the higher costs to continue throughout 2015. In addition, we are currently engaged in litigation with our contract operator and its affiliates, which has affected our exploration and production related cash flow. See “Note 12 - Commitments and Contingencies” to our unaudited condensed consolidated financial statements in this report for additional discussion of this litigation. Based on expected lower commodity prices, higher production costs and less drilling activity, we estimate revenue, operating income and cash flow from operations for our exploration and production business will decline in 2015 from levels in 2014. In an effort to minimize the impact of anticipated reductions in cash flows from operations, management has significantly reduced its 2015 capital expenditures for exploration and production activities with minimal maintenance activities planned for existing wells and no currently planned drilling activity. As noted above, drilling activity is primarily dependent on commodity prices. Although we hold a non-operator working interest in our oil and natural gas properties, we can elect to not participate in drilling new wells proposed by our contract operator. The penalty for not participating varies by area, but is generally a loss in our ability to participate in offset drilling locations drilled in the future. Typically, when we elect to not participate or recommend to defer maintenance activities we believe are not economically beneficial, our contract operator terminates the drilling proposal or delays maintenance activity.

For purposes of determining the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves and calculating our full cost ceiling limitation, we use 12-month average oil, natural gas, and NGL 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. Continued low levels or further declines in oil, natural gas and NGL prices are expected to result in impairments to our oil and natural gas properties in multiple quarters in 2015. Additionally, as a non-operator of our properties, we cannot control the costs our contract 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 the 12-month average prices of oil, natural gas and NGLs as of March, 31, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015. Continued low levels or further declines in oil, natural gas and NGL prices subsequent to March 31, 2015 are expected to result in additional ceiling test write downs in the second quarter of 2015 and in subsequent periods. The amount of any future impairment is difficult to predict, and will primarily depend on oil, natural gas and NGL prices during these periods.

Our credit facility is limited to a borrowing base amount determined by the lenders at their sole discretion, based on their valuation of our proved reserves and their other internal criteria. At March 31, 2015, the borrowing base under the credit facility was $90.0 million. In April 2015, our borrowing base was decreased from $90.0 million to $84.0 million and the semi-annual redetermination was moved to May 2015. On May 8, 2015, the borrowing base was reduced to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. As outstanding borrowings under our credit facility exceeded the new borrowing base resulting from the redetermination, we are required to eliminate this excess. On May 8, 2015, the Partnership remitted payment of $41.0 million which resulted in an outstanding balance under our credit facility of $43.0 million. Distributions to common unitholders are permitted as long as the amount outstanding is 90% or less of the current borrowing base. Accordingly, we are currently permitted to pay distributions in May 2015.

35

Oilfield Services. As an oilfield services provider of wellsite services during the drilling and completion stages of a well, our business depends substantially on the capital spending programs of our customers. Revenue from our oilfield services segment is generated by providing services to oil and natural gas exploration and production companies located in the Mid-Continent region (Oklahoma, Kansas and the Texas Panhandle), the Permian Basin region (Texas and New Mexico), the Eagle Ford shale region in South Texas, and the Marcellus and Utica shale regions (Pennsylvania, Ohio and West Virginia). Demand for our services is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the areas in which we operate, which in turn is affected by current and expected levels of oil, natural gas, and NGL prices. Due to the decline in oil, natural gas, and NGL prices noted in the fourth quarter of 2014 and continuing into 2015, a trend of decreased drilling activity and planned capital expenditures by our exploration and production customers has occurred. Additionally, our customers are allocating drilling resources away from certain less-profitable basins to those basins with better economics. We believe drilling activity will continue to be curtailed until oil prices improve. As a result of the recent decline in commodity prices, the market for oilfield services has experienced downward pricing pressure, which has caused us to offer reduced rates for our services. In an effort to retain our customer base and maintain our market share, we are working with our customers to provide competitive rates for our services until commodity prices improve to more favorable levels. We expect that these competitive rates coupled with our strong safety record and existing customer relationships will provide growth opportunities in the areas we provide services.

A decrease in the demand for our oilfield services coupled with our offering of pricing discounts on our services has resulted and is expected to continue to result in lower revenues and cash flows from operations on our oilfield services business. We have implemented and continue to effect cost cutting efforts in order to address the impact of anticipated reductions in revenue and cash flows from operations. Such cost cutting efforts include seeking discounts from our vendors, reductions to compensation and reductions to capital expenditures. We began implementing certain cost reductions during the first quarter of 2015 with additional cost reductions becoming effective in the second quarter of 2015. To the extent cost cutting efforts are not fully realized, the profit on our oilfield services could decline. Maintenance capital expenditures for 2015 are expected to be lower than in 2014, and any growth capital expenditures in 2015 will be completely discretionary and based on our customers' drilling activity levels.

If market conditions decline and a triggering event is deemed to have occurred for purposes of evaluating goodwill or our intangible assets of our oilfield services segment, then we could have an additional impairment to one or more of these assets.

Corporate. We expect to utilize various financing sources, including equity issuances, in order to fund our capital budget, pay distributions to our unitholders and address other liquidity needs, including repayment of current debt obligations, payment of the cash portion of contingent consideration and payment of a portion of the outstanding balance under our credit facility. In addition to the items noted above, we have taken additional steps to address potential shortfalls in cash flow from operations necessary to fund our investing and financing activities. In May 2015, we completed a public offering of $44.0 million of our Series A Preferred Units and used the net proceeds from the offering to repay a portion of the indebtedness outstanding under our revolving credit facility. We maintained the quarterly distribution of $0.20 per unit, or $0.80 per unit on an annual basis. This distribution rate takes into consideration current commodity and financial market conditions and helps to preserve our liquidity. We refinanced our EFS term loan to extend the maturity date from June 2015 to March 2018, which reduced our monthly debt payments. We also extended the date on which the cash portion of the EFS/RPS Contingent Consideration is due to the former owners of EFS and RPS from May 2015 to May 2016.

If the above discussed steps are not sufficient to address our cash flow requirements, we can undertake some or all of the following:

•sell common units through our existing EDA;

•pursue additional financing for our oilfield services business;

•monetize our derivative portfolio; and

•maintain lower distributions to our common unitholders for additional quarters.

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. Additionally, due to declines in oil, natural gas, and NGL prices in 2015, access to capital markets may be limited or costs associated with issuing debt may be higher due to increased interest rates, and may affect our ability to access these markets. 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 and our financial condition. Additionally, the issuance of common units, whether through equity offerings or to settle our contingent consideration obligations, will result in a higher number of units for which we will pay distributions.

36

We expect a combination of the actions noted above will be sufficient to enable us to meet our cash flow needs through at least March 2016. However, if we are unsuccessful or market environments are worse than expected, we may be unable to obtain the necessary cash flow needed to meet our obligations.

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 key factors in assessing our operating results and profitability and include (i) revenues, (ii) direct 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 months ended March 31, 2015 and 2014 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 and drilling plans. 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 NGL fluctuate widely and are difficult to predict. Additionally, we have a non-operator position in our oil and natural gas properties, which limits the control we have over certain costs incurred to produce oil, natural gas and NGLs. Our contract operator is a related party. See “Note 9 - Related Party Transactions” to our unaudited condensed consolidated financial statements in this report for additional discussion.

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 certain 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."

37

Set forth in the table below is financial, production and pricing information for our exploration and production segment for the three months ended March 31, 2015 and 2014.

	Three Months Ended March 31,
	2015			2014
Results (in thousands):
Oil sales	$	1,692		$	3,947
Natural gas sales	1,843			5,367
NGL sales	3,032			9,537
Total revenues	6,567			18,851
Production expenses	4,055			4,503
Production taxes	311			879
Total segment margin	2,201			13,469
Depreciation, depletion, amortization and accretion	4,794			5,887
Impairment	43,119			—
General and administrative	4,569			3,843
Operating (loss) income	$	(50,281	)	$	3,739
Production volumes:
Oil (Bbls)	37,561			40,681
Natural gas (Mcf)	736,758			988,216
NGLs (Bbls)	189,689			205,583
Total production volumes (Boe)	350,043			410,967
Average daily production volumes (Boe)	3,889			4,566
Average price (excluding derivatives):
Oil (per Bbl)	$	45.05		$	97.02
Natural gas (per Mcf)	$	2.50		$	5.43
NGL (per Bbl)	$	15.98		$	46.40
Total (per Boe)	$	18.76		$	45.87
Average production costs (per Boe)(1)	$	11.58		$	10.96

__________

(1) Includes lease operating expense and workover expense.

Revenue

Revenues from our exploration and production segment were $6.6 million for the three months ended March 31, 2015, a decrease of $12.3 million, or 65.2%, compared to the three months ended March 31, 2014. The decrease in revenues during the three months ended March 31, 2015 was primarily due to lower commodity prices and lower production. The average price per Boe received on our combined production decreased $27.11, or 59.1%, in the three months ended March 31, 2015 from the same period in 2014. Additionally, combined production decreased 60,924 Boe, or 14.8%, in the three months ended March 31, 2015 from the same period in 2014 primarily due to our suspension of drilling activity until commodity prices are more favorable and the expected natural production decline rate of our properties. The reduction in drilling activity has impacted our ability to replace reserves and offset declining production.  In addition, an increased number of our wells required submersible pump repairs resulting in extended downtime in the Southern Dome field. 

38

Operating Expenses

Production expenses. Production expenses include costs associated with exploration and production activities, including lease operating expense and treating costs. Production expenses decreased $0.4 million, or 9.9%, for the three months ended March 31, 2015 from the three months ended March 31, 2014. The decrease in production expenses for the three months ended March 31, 2015 was partially due to lower production, offset by higher production costs in the Southern Dome field and certain fixed overhead charges from our operator. Higher production costs were incurred on oil production in the Southern Dome field compared to production costs on natural gas in our other producing areas. In addition, we incurred higher operator fees and costs on our production in 2015. As a result of these factors, production expense increased $0.62 per Boe for the three months ended March 31, 2015, compared to the same period in 2014. 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. See further discussion related to our contract operator in Note 9 "Related Party Transactions" and Note 12 "Commitments and Contingencies" to the Partnership’s consolidated financial statements in Item 1. "Financial Statements" of this report.

Production taxes. Production taxes decreased $0.6 million, or 64.6%, in the three months ended March 31, 2015, from the same period in 2014. The decrease in production taxes is due to lower production volumes and lower commodity prices received on our production in 2015 versus 2014. 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.

Depreciation, depletion, amortization, and accretion. Depreciation, depletion, amortization and accretion expense decreased $1.1 million for the three months ended March 31, 2015 from the comparable period in 2014. The majority of the decrease in depreciation, depletion and amortization is attributable to the declines in production, partially offset by an increase in the depletion rate.

Impairment. Based on the 12-month average prices of oil, natural gas and NGLs as of March, 31, 2015, we recorded an impairment of our oil and natural gas properties of $43.1 million during the first quarter of 2015. The impairment is a result of lower commodity prices and our suspension of drilling activity in late 2014 and continuing in the first quarter of 2015.

General and administrative. General and administrative expense increased $0.7 million, or 18.9%, for the three months ended March 31, 2015 from the same period in 2014. As the exploration and production segment's general and administrative expenses include certain costs of our corporate administrative functions, such expenses are expected to remain fairly consistent across periods. Equity compensation for the three months ended March 31, 2015 was $1.2 million compared to $0.3 million for the same period in 2014. The increase in equity compensation in the three months ended March 31, 2015 was primarily due to common units granted in 2015 that immediately vested. Partially offsetting the increase in equity compensation was $0.4 million for the change in the fair value of contingent consideration that was reflected in the three months ended March 31, 2014.

Oilfield Services Segment

The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. 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. The primary factors affecting the results of the oilfield services segment are the rates received and the amount of oilfield services provided.

39

	Three Months Ended March 31,
	2015			2014
Results (in thousands):
Oilfield service revenue	$	31,550		$	8,576
Cost of providing oilfield services	23,059			4,566
Total segment margin	8,491			4,010
Depreciation and amortization	7,627			3,460
General and administrative	7,665			1,717
Operating loss	$	(6,801	)	$	(1,167	)

Revenue

Oilfield services revenues fluctuate based on drilling activity in the areas in which we operate. Revenues from our oilfield services segment were $31.6 million and $8.6 million for the three months ended March 31, 2015 and 2014, respectively. The increase of $23.0 million is primarily due to expanded operations achieved through the Services Acquisition. Revenue from operations acquired in the Services Acquisition contributed $23.9 million of revenue for our oilfield services segment during the three months ended March 31, 2015.

Operating Expenses

Cost of providing oilfield services. The cost of providing oilfield services was $23.1 million and $4.6 million for the three months ended March 31, 2015 and 2014, respectively. The increase of $18.5 million reflects $17.0 million of costs for the three months ended March 31, 2015 related to the operations of EFS and RPS.

General and administrative. General and administrative expense consists of compensation for non-field employees, selling expenses, professional fees and occupancy costs. General and administrative expense was $7.7 million and $1.7 million for the three months ended March 31, 2015 and 2014, respectively. The increase reflects our expanded operations in our oilfield services segment. Additionally, equity compensation which primarily related to expense on the phantom units issued in conjunction with the Services Acquisition, of $2.3 million was included in general and administrative expenses for the three months ended March 31, 2015

Depreciation and amortization. Depreciation and amortization expense of $7.6 million and $3.5 million for the three months ended March 31, 2015 and 2014, respectively, increased due to expanded operations. The $4.1 million increase is primarily related to the Services Acquisition in June 2014, including amortization of the intangible assets identified in the Services Acquisition.

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

40

Results of Operations

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

		Three Months Ended March 31,
		2015			2014
	(in thousands)
Operating (loss) income		$	(57,082	)	$	2,572
Other income (expense):
Interest expense		(1,348		)	(969		)
Gain (loss) on derivative contracts, net		1,224			(3,132		)
Other income (expense)		34			(2		)
Net loss		$	(57,172	)	$	(1,531	)

Other Income/Expense

Interest expense. Interest expense increased $0.4 million, or 39.1%, for the three months ended March 31, 2015 from the three months ended March 31, 2014. The increase was due to higher average debt balances in 2015 compared to 2014, primarily as a result of additional borrowings under our credit facility as a result of corporate growth and the addition of debt in our oilfield services segment.

Gain (loss) on derivatives, net. The following table presents gain (loss) on our derivative contracts for the three months ended March 31, 2015 and 2014 (in thousands):

	Three Months Ended March 31,
	2015		2014
Total gain (loss) on derivative contracts, net (1)	$	1,224	$	(3,132	)

__________

(1) Included in gain (loss) on derivative contracts for the three months ended March 31, 2015 and 2014 are net cash receipts (payments) upon contract settlement of $2.3 million and $(2.4) million, respectively.

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.

Non-GAAP Financial Measures

Adjusted EBITDA. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, and is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.

41

A reconciliation of Adjusted EBITDA to net loss for the three months ended March 31, 2015 and 2014 is provided below:

	Three Months Ended
	March 31,
	2015			2014
Reconciliation of adjusted EBITDA to net loss:	(in thousands)
Net loss attributable to New Source Energy Partners L.P.	$	(57,172	)	$	(1,531	)
Interest expense	1,348			969
Depreciation, depletion and amortization	12,347			9,279
Accretion expense	74			68
Impairment of oil and natural gas properties	43,119			—
Non-cash compensation expense	3,861			258
Transaction fees	694			1,911
(Gain) loss on derivative contracts, net	(1,224		)	3,132
Cash received (paid) on settlement of derivative contracts	2,339			(2,429		)
Other	719			—
Change in fair value of contingent consideration	—			433
Adjusted EBITDA	$	6,105		$	12,090

A reconciliation of Adjusted EBITDA to net loss for our exploration and production and oilfield services segments for the three months ended March 31, 2015 is provided below:

	Three Months Ended
	March 31, 2015
	E&P			OFS
Reconciliation of adjusted EBITDA to net loss:	(in thousands)
Net loss attributable to New Source Energy Partners L.P.	$	(49,922	)	$	(7,250	)
Interest expense	867			481
Depreciation, depletion and amortization	4,720			7,627
Accretion expense	74			—
Impairment of oil and natural gas properties	43,119			—
Non-cash compensation expense	1,226			2,635
Transaction fees	694			—
Gain on derivative contracts, net	(1,224		)	—
Cash received on settlement of derivative contracts	2,339			—
Other	378			341
Adjusted EBITDA	$	2,271		$	3,834

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under existing debt instruments by our oilfield services subsidiaries and the issuance of equity securities in the capital markets. To date, our primary uses of capital have been for the acquisition of our oilfield services business through the MCE Acquisition and the Services Acquisition, distributions to our unitholders, working capital needs, and acquisition and development of oil and natural gas properties.

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, and to pay distributions to our unitholders depends 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, capital expenditures of our oilfield services customers 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.

42

Refer to "Outlook" above for a discussion of our 2015 outlook, including discussion of liquidity and capital resources.

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. 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 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.

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. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the three months ended March 31, 2015 and 2014, are shown in the following table (in thousands, except per unit amounts):

Distributions	Payable Date	Distribution per Unit		Common Units		Subordinated Units		General Partner Units		Total
2015
First Quarter	May 15, 2015	$	0.20	$	3,312	$	—	$	—	$	3,312
2014
First Quarter	May 15, 2014	$	0.580	$	7,852	$	1,279	$	90	$	9,221

Cash Flows

Operating. Cash provided by operating activities is impacted by the prices we are able to charge for our oilfield services, prices received for oil, natural gas, and NGL sales and levels of production. Production volumes in the future will be largely dependent upon the amount of and results of future capital expenditures. Future levels of capital expenditures may vary due to many factors, including drilling results, commodity prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

Net cash provided by operating activities was approximately $8.7 million and $6.4 million for the three months ended March 31, 2015 and 2014, respectively. The increase in cash provided by operating activities is a result of the oilfield service acquisitions that occurred in 2014 which increased the Partnership's revenue from oilfield services. This increase was partially offset by decreased revenues from oil, natural gas and NGL production as a result of declines in commodity prices and production volumes.

Investing. Cash flows used in investing activities are related to acquisitions and capital expenditures for the development of our oil and natural gas properties and equipment for our oilfield services business. Net cash used in investing activities was approximately $6.2 million and $18.1 million for the three months ended March 31, 2015 and 2014, respectively. The decrease is primarily attributable to the CEU Acquisition in 2014 combined with our decision in late 2014 to suspend drilling activity until commodity prices are more favorable. These decreases are partially offset by capital expenditures for our oilfield services segment as a result of expanded operations. Capital expenditures for the three months ended March 31, 2015 were primarily related to new facilities for our oilfield services segment.

43

Financing. Financing cash flows are primarily related to debt and equity financing of property development and acquisitions and working capital. Net cash (used in) provided by financing activities was approximately $(6.5) million and $5.3 million for the three months ended March 31, 2015 and 2014, respectively. Net cash used in financing activities for the three months ended March 31, 2015 reflects payments in excess of proceeds on borrowings. For the three months ended March 31, 2014, proceeds from borrowings exceeded all other uses of cash for financing activities.

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 changes in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, debt repayments and contingent consideration.

Our working (deficit) capital was $(5.5) million and $3.4 million at March 31, 2015 and December 31, 2014, respectively. The working deficit is primarily attributable to reduced operating cash flow and lower accounts receivable related to the reduction in sales in both segments during the three months ended March 31, 2015. The former owners of EFS and RPS are entitled to receive additional consideration in the form of common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments. Excluding the liability related to this contingent consideration, which is to be paid in common units, working capital at March 31, 2015 and December 31, 2014 would have been $6.1 million and $15.0 million, respectively.

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 are 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, maintenance capital expenditures represent the actual costs incurred to perform workover and other maintenance activities on our existing wells. With respect to our oilfield services operations, maintenance capital expenditures represent the actual costs incurred to replace fixed assets necessary to maintain our current oilfield service operations. Due to current market conditions, we have curtailed drilling activity and reduced our investment level to maintain the lower levels of operation. For the three months ended March 31, 2015 and 2014, our maintenance capital expenditures were approximately $1.0 million and $3.4 million, respectively. The decrease in maintenance capital expenditures in 2015 is due to our suspension of drilling activity and the minimal number of workovers performed on existing wells.

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 oil and natural gas 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 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 debt instruments, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions.

Because 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 and services, there can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our current production levels. Our drilling activity for 2015 is limited and dependent on commodity prices. If we do not pursue drilling activities, our reserves 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, demand for our oilfield services and prices we can charge for such services, and 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, and impact our ability to purchase additional equipment for our oilfield services business.

44

Credit Facility

Our credit facility is a four-year, senior secured credit facility. Our credit facility is subject to a borrowing base which is generally set by the bank semi-annually on April 1 and October 1 of each year. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. If outstanding borrowings under our credit facility exceed the new borrowing base as a result of a redetermination, we are required to eliminate this excess through (1) payment of the total amount of the excess within 30 days or in equal monthly installments over a three-month period; (2) a lien on oil and gas properties we own for sufficient consideration; or (3) a combination of repayments and the submission of additional oil and gas properties within 30 days. Additionally, if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we are prohibited from paying distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our credit facility.

At March 31, 2015, the borrowing base under the credit facility was $90.0 million. In April 2015, our borrowing base was decreased from $90.0 million to $84.0 million and the semi-annual redetermination was moved to May 2015. On May 8, 2015, the borrowing base was reduced to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. As outstanding borrowings under our credit facility exceeded the new borrowing base resulting from the redetermination, we are required to eliminate this excess. On May 8, 2015, the Partnership remitted payment of $41.0 million which resulted in an outstanding balance under our credit facility of $43.0 million. Distributions to common unitholders are permitted as long as the amount outstanding is 90% or less of the current borrowing base. Accordingly, we are currently permitted to pay distributions in May 2015.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At March 31, 2015 and December 31, 2014, the average annual interest rate on borrowings outstanding under the credit facility was 3.51% and 3.44%, respectively.

As of March 31, 2015, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of all subsidiaries. As of March 31, 2015, the Partnership was in compliance with all covenants under the credit facility.

Notes Payable

MCES Notes Payable. The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. The notes range from 12 to 60 months in duration with maturity dates from August 2015 through March 2019 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. The Partnership had $6.5 million outstanding under the MCES notes payable as of March 31, 2015.

EFS Loan Agreement. In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on EFS term loans, which were originally set to mature on June 26, 2015. In March 2015, we refinanced the EFS' notes payable to extend the maturity date to March 2018. The balance on the note payable was $11.7 million as of March 31, 2015.

The note payable has a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at March 31, 2015, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The note payable is collateralized by various assets of the parties to the agreement and guaranteed by MCE. The Partnership is required to maintain a reserve bank account into which $0.3 million shall be deposited quarterly beginning after the initial deposit of $0.5 million on September 30, 2015, and used to fund an additional annual payment on September 30th of each year during the term of the loan.

45

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, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0, (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $1.0 million by June 30, 2015 increasing to at least $3.5 million by October 1, 2015, in each case as more fully described in the loan agreement. As of March 31, 2015, EFS and RPS were in compliance with the covenants under the loan agreement.

MCES Promissory Notes. On January 9, 2015 and February 24, 2015, MCES issued promissory notes totaling approximately $1.4 million to acquire land from entities owned 50% by Mr. Kos, Chief Executive Officer of our general partner, and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner. Both promissory notes bear interest at prime plus one percent and are payable, including all accrued interest, on December 31, 2015. No payments are due prior to maturity.

EFS/RPS Contingent Consideration.  In March 2015, we entered into an agreement with the former owners that allows for the payment of the cash portion of the EFS/RPS Contingent Consideration to be extended to May 2016. Beginning in June 2015, interest payments are due monthly with principal and any unpaid interest due May 1, 2016. This agreement also restricts equity compensation and bonus payments to certain officers of the Partnership as well as the Partnership's ability to acquire another entity until this liability has been paid. See Note 12 "Commitments and Contingencies" for discussion of the contingent consideration.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. Interest only payments are due monthly with the line of credit which was set to mature in May 2015, but was extended to mature on June 25, 2015. Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at March 31, 2015. The line of credit is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. Based on the outstanding balance of $3.4 million, there was $0.6 million of available borrowing capacity at March 31, 2015.

The line of credit contains a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of March 31, 2015, MCES was in compliance with this covenant under the line of credit.

Factoring Payable

In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 3% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not collected within 90 days, the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $11.4 million as of March 31, 2015.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements and operating leases. Our operating leases primarily relate to office facilities and equipment. During the three months ended March 31, 2015, there were no material changes to our contractual commitments since December 31, 2014.

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.

46

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 2014 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 for a portion of our estimated total production. 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.

At March 31, 2015, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

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

The following tables present our derivative instruments outstanding as of March 31, 2015:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2015	30,072	$	80.00	$	93.25

47

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	27,500	$	77.50	$	92.50	$	102.60

Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	30,080	$	88.90
2016	36,658	$	86.00

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2015	976,356	$	4.00	$	4.32

Natural gas put options	Volumes (MMBtu)	Floor Price
2015	620,040	$	3.50
2016	930,468	$	3.50

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2015	582,451	$	4.25
2016	629,301	$	4.37

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	62,213	$	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 months ended March 31, 2015 and 2014 (in thousands):

	Three Months Ended March 31,
	2015		2014
Total gain (loss) on derivative contracts, net (1)	$	1,224	$	(3,132	)

__________

(1) Included in the gain (loss) on derivative contracts for the three months ended March 31, 2015 and 2014 are net cash receipts (payments) upon contract settlement of $2.3 million and $(2.4) million, respectively.

See Note 5 "Derivative Contracts" to the accompanying unaudited condensed consolidated financial statements included in this Quarterly Report for additional information regarding our commodity derivatives.

48

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 consider 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 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 March 31, 2015, 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 our derivative contracts.

Interest Rate Risk

At March 31, 2015, we had debt outstanding under our credit facility of $84.0 million. A 1% increase in LIBOR on our outstanding debt under our credit facility as of March 31, 2015 would result in an estimated $0.8 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 March 31, 2015. 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 March 31, 2015 at the reasonable assurance level due to the material weaknesses in internal control over financial reporting we identified in connection with preparing the 2014 Form 10-K. The material weaknesses we identified, as disclosed in the 2014 Form 10-K, 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 year ended December 31, 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.

49

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 March 31, 2015, 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.

Changes in Internal Control over Financial Reporting

There was no change in the Company’s internal control over financial reporting during the quarter ended March 31, 2015 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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.

50

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.

On January 12, 2015, David J. Chernicky, the beneficial owner of approximately 30.6% of our general partner, approximately 15.6% of our common units and all of our subordinated units, and his affiliated entities, Scintilla, LLC, New Source Energy Corporation and New Dominion, LLC (collectively, “plaintiffs”) filed a lawsuit against the Partnership, our general partner and certain current officers of our general partner, including Chairman and Chief Executive Officer, Kristian Kos, and Chief Financial Officer, Richard Finley, and certain of their affiliated entities (collectively, “defendants”) in the District Court of Tulsa County, Oklahoma. The plaintiffs allege various claims against the defendants, including that plaintiffs did not receive fair value for various oil and natural gas working interests acquired from them by the Partnership. The plaintiffs also allege that the Partnership has been unjustly enriched and that the properties acquired from them by the Partnership pursuant to the transactions in question should be held in a constructive trust in favor of the plaintiffs. Additionally, the plaintiffs claim that the defendants have conspired to commit constructive fraud, breach of fiduciary duty, negligence and gross negligence against the plaintiffs. Additionally, the plaintiffs allege that the defendants have intentionally interfered with the defendants' current business arrangements with certain working interest owners in the properties the plaintiffs operate as well as future business opportunities. The plaintiffs also claim that the Partnership is wrongfully refusing to remove the restrictive legends on common units issued by the Partnership to the plaintiffs in private transactions in exchange for the oil and natural gas working interests described above.

On February 23, 2015, the defendants filed several motions to dismiss the claims raised in the plaintiffs’ petition, including motions by the Partnership and our general partner that (i) the defendants' claims fail to state a claim; (ii) the defendants' claims are time barred by statues of limitations; and (iii) Tulsa County is an improper venue. A hearing on the motions to dismiss is currently scheduled to be held on May 26, 2015. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action.

In addition to the proceeding described above, on January 29, 2015, the Partnership received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by the Partnership to NSEC. The total amount of the purported claims totaled approximately $1.9 million. In 2015, New Dominion withheld all revenue from the Partnership's sold oil and natural gas production in satisfaction of these claims as well as other amounts that the Partnership has disputed. As with the proceeding described above, the Partnership intends to pursue this matter vigorously and believes the claims are without any substantial merit. The Partnership has not established any reserves relating to this action.

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

In the case of Mattingly v. Equal Energy, LLC, New Dominion is a named defendant. In this case, the plaintiffs assert claims on behalf of a class of royalty owners in wells operated by New Dominion and others from which natural gas is sold by New Dominion to Scissortail Energy, LLC ("Scissortail"). The plaintiffs assert that royalties to the class should be paid based upon the price received by Scissortail for the natural gas and its components at the tailgate of the plant, rather than the price paid by Scissortail at the wellhead where the natural gas is purchased. The plaintiffs assert a variety of breach of contract and tort claims. A hearing on the matter was held in August 2014 at which Scissortail’s motion to dismiss was granted with prejudice and New Dominion’s motion to dismiss was granted in part. The plaintiffs have appealed the court's granting of the dismissal. In January, the appeal was assigned to the Court of Civil Appeals in Tulsa, Oklahoma. A class certification hearing has also been set for November 2015.

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.

51

ITEM 1A. Risk Factors

The following risk factors update the risk factors included in our Annual Report. Except as set forth below, there have been no material changes to the Risk Factors disclosed in Item 1A. Risk Factors in our 2014 Form 10-K.

Risks Related to Our Series A Preferred Units

We must continue to generate cash from operations in order to pay distributions on the Series A Preferred Units.

The amount of cash we generate from operations depends on, among other things:

• the amount of oil, natural gas and NGLs we produce;

• the prices at which we sell our oil, natural gas and NGL production;

• the amount and timing of settlements of our commodity derivatives;

• the level of our operating costs, including maintenance capital expenditures and payments to our general partner; and

• the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.

The Series A Preferred Units have not been rated.

We have not sought to obtain a rating for the Series A Preferred Units, and the Series A Preferred Units may never be rated. It is possible, however, that one or more rating agencies might independently determine to assign a rating to the Series A Preferred Units or that we may elect to obtain a rating of the Series A Preferred Units in the future. In addition, we may elect to issue other securities for which we may seek to obtain a rating. If any ratings are assigned to the Series A Preferred Units in the future or if we issue other securities with a rating, such ratings, if they are lower than market expectations or are subsequently lowered or withdrawn, could adversely affect the market for or the market value of the Series A Preferred Units. Ratings only reflect the views of the issuing rating agency or agencies and such ratings could at any time be revised downward or withdrawn entirely at the discretion of the issuing rating agency. A rating is not a recommendation to purchase, sell or hold any particular security, including the Series A Preferred Units. Ratings do not reflect market prices or suitability of a security for a particular investor, and any future rating of the Series A Preferred Units may not reflect all risks related to us and our business, or the structure or market value of the Series A Preferred Units.

We distribute all of our available cash each quarter and are not required to accumulate cash for the purpose of meeting our future obligations to holders of the Series A Preferred Units, which may limit the cash available to make distributions on the Series A Preferred Units.

Subject to the limitations in our partnership agreement, we distribute all of our available cash each quarter to our limited partners. “Available cash” is defined in our partnership agreement, and it generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

•less, the amount of cash reserves established by our general partner at the date of determination of available cash for the quarter to:

•provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for future capital expenditures and for our anticipated future credit needs after the end of the quarter;

•comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation of ours; or

•provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters;

52

•plus, if our general partner so determines, all or a portion of any additional cash on hand immediately prior to the date of distribution of available cash with respect to the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from borrowing (including working capital borrowings) made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders.

As a result, we do not expect to accumulate significant amounts of cash. Depending on the timing and amount of our cash distributions, these distributions could significantly reduce the cash available to us in subsequent periods to make distribution payments on the Series A Preferred Units.

The Series A Preferred Units rank junior to all of our indebtedness and other liabilities, and your interests could be diluted by the issuance of additional units, including additional Series A Preferred Units, and by other transactions.

In the event of our bankruptcy, liquidation, reorganization or other winding-up, our assets will be available to pay obligations on the Series A Preferred Units only after all of our indebtedness and other liabilities have been paid. In addition, the Series A Preferred Units will effectively rank junior to all existing and future indebtedness and other liabilities (including trade payables) of our subsidiaries and any equity securities of our subsidiaries not held by us. The rights of holders of the Series A Preferred Units to participate in the distribution of assets of our subsidiaries will rank junior to the prior claims of that subsidiary’s creditors and any other equity holders. Consequently, if we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets remaining to pay amounts due on any or all of the Series A Preferred Units then outstanding. We and our subsidiaries may incur substantial amounts of additional debt and other obligations that will rank senior to the Series A Preferred Units.

We currently have no preferred units outstanding and no other equity securities outstanding that are senior to or on parity with the Series A Preferred Units.

We may issue additional series of preferred units that rank equally or senior to the Series A Preferred Units as to distribution payments. The issuances of other series of preferred units could have the effect of reducing the amounts available to the Series A Preferred Units in the event of our liquidation, winding-up or dissolution. The issuance of additional units pari passu with or senior to the Series A Preferred Units would dilute the interests of the holders of the Series A Preferred Units, and any issuance of senior securities or parity securities or additional indebtedness could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Units.

As a holder of Series A Preferred Units you have extremely limited voting rights.

Your voting rights as a holder of Series A Preferred Units will be extremely limited. Our common units are the only class of limited partner interests carrying full voting rights. Holders of the Series A Preferred Units generally have no voting rights. Certain other limited protective voting rights are described in our partnership agreement.

The Series A Preferred Units are a new issuance and do not have an established trading market, which may negatively affect their market value and your ability to transfer or sell your units.

The Series A Preferred Units are a new issue of securities with no established trading market. We intend to apply to list the Series A Preferred Units on the NYSE, but there can be no assurance that the NYSE will accept the Series A Preferred Units for listing. Even if the Series A Preferred Units are approved for listing by the NYSE, an active trading market on the NYSE for the Series A Preferred Units may not develop or, even if it develops, may not last, in which case the trading price of the Series A Preferred Units could be adversely affected and your ability to transfer your units will be limited. If an active trading market does develop on the NYSE, our Series A Preferred Units may trade at prices lower than the offering price. The trading price of our Series A Preferred Units would depend on many factors, including:

•prevailing interest rates;

•the market for similar securities;

•general economic and financial market conditions;

53

•our issuance of debt or preferred equity securities; and

•our financial condition, results of operations and prospects.

Market interest rates may adversely affect the value of the Series A Preferred Units.

One of the factors that will influence the price of the Series A Preferred Units will be the distribution yield on the Series A Preferred Units (as a percentage of the price of the Series A Preferred Units) relative to market interest rates. An increase in market interest rates, which are currently at low levels relative to historical rates, may lead prospective purchasers of the Series A Preferred Units to expect a higher distribution yield, and higher interest rates would likely increase our borrowing costs and potentially decrease funds available for distribution. Accordingly, higher market interest rates could cause the market price of the Series A Preferred Units to decrease.

The terms of our revolving credit facility and other financing agreements may limit our ability to pay distributions on the Series A Preferred Units.

Our current revolving credit facility contains restrictions on, and any credit facilities or other debt instrument that we enter into in the future may contain restrictions on, our ability to pay cash distributions on our equity securities, including the Series A Preferred Units. These limitations may cause us to be unable to pay distributions on the Series A Preferred Units unless we can refinance amounts outstanding under those agreements. Since we are not obligated to declare or pay distributions, we do not intend to do so to the extent we are restricted by any of our financing agreements. No allowance or adjustment will be made upon conversion for any undeclared or, subject to limited exceptions, unpaid distributions.

Recent regulatory actions may adversely affect the trading price and liquidity of the Series A Preferred Units.

Some investors in, and potential purchasers of, the Series A Preferred Units may employ, or seek to employ, a convertible arbitrage strategy with respect to the Series A Preferred Units. Investors that employ a convertible arbitrage strategy with respect to convertible securities typically implement that strategy by selling short the security underlying the convertible security (i.e., our common units in the case of the Series A Preferred Units) and dynamically adjusting their short position while they hold the convertible security. Investors may also implement this strategy by entering into swaps on the underlying security in lieu of or in addition to short selling the underlying security. As a result, any specific rules regulating equity swaps or short selling of securities or other governmental action that interferes with the ability of market participants to effect short sales or equity swaps with respect to our common units could adversely affect the ability of investors in, or potential purchasers of, the Series A Preferred Units to conduct the convertible arbitrage strategy that we believe they will employ, or seek to employ, with respect to the Series A Convertible Preferred Units. This could, in turn, adversely affect the trading price and liquidity of the Series A Convertible Preferred Units.

The SEC and other regulatory and self-regulatory authorities have implemented various rules and taken certain actions, and may in the future adopt additional rules and take other actions, that may impact those engaging in short selling activity involving equity securities (including our common units). These rules and actions include Rule 201 of SEC Regulation SHO, the adoption by the Financial Industry Regulatory Authority, Inc. and the national securities exchanges of a “Limit Up-Limit Down” program, the imposition of market-wide circuit breakers that halt trading of securities for certain periods following specific market declines, and the implementation of certain regulatory reforms required by the Dodd-Frank Wall Street Reform and Consumer Protection Act. Any governmental or regulatory action that restricts the ability of investors in, or potential purchasers of, the Series A Preferred Units to effect short sales of our common units or enter into swaps on our common units could adversely affect the trading price and the liquidity of the Series A Preferred Units.

In addition, if investors and potential purchasers seeking to employ a convertible arbitrage strategy are unable to borrow or enter into swaps on our common units, in each case on commercially reasonable terms, the trading price and liquidity of the Series A Preferred Units may be adversely affected.

The conversion rate of the Series A Preferred Units may not be adjusted for all dilutive events.

54

The number our common units that you are entitled to receive upon conversion of the Series A Preferred Units is subject to adjustment for certain specified events, including, but not limited to, the issuance of certain unit distributions on our common units, the issuance of certain rights or warrants, subdivisions, combinations, distributions of equity securities, indebtedness, or assets, cash distributions and certain issuer tender or exchange offers, as described in our partnership agreement. However, the conversion rate may not be adjusted for other events, such as the exercise of unit options held by our employees or offerings of our common units or securities convertible into common units (other than those set forth in our partnership agreement) for cash or in connection with acquisitions, which may adversely affect the market price of our common units. Further, if any of these other events adversely affects the market price of our common units, we expect it to also adversely affect the market price of our Series A Preferred Units. In addition, the terms of our Series A Preferred Units do not restrict our ability to offer common units or securities convertible into common units in the future or to engage in other transactions that could dilute our common units. We have no obligation to consider the interests of the holders of our Series A Preferred Units in engaging in any such offering or transaction. If we issue additional common units, those issuances may materially and adversely affect the market price of our common units and, in turn, those issuances may adversely affect the trading price of the Series A Preferred Units.

The additional common units deliverable for Series A Preferred Units converted in connection with a fundamental change may not adequately compensate you.

If a “fundamental change” (as defined in our partnership agreement) occurs, we will under certain circumstances increase the conversion rate by a number of additional common units for Series A Preferred Units converted in connection with such fundamental change as described in our partnership agreement. The number of additional common units will be determined based in part on the date on which the fundamental change occurs or becomes effective and the price paid (or deemed to have been paid) per common unit in the fundamental change as described in our partnership agreement .While this feature is designed to compensate you for any lost option time value of your Series A Preferred Units as a result of the fundamental change, the number of additional units due upon conversion is only an approximation of this lost option time value and may not adequately compensate you for your loss as a result of such transaction. In addition, if the unit price for such transaction (as determined under our partnership agreement) is in excess of $12.00 per unit, or if such price is less than $5.75 per unit, in each case subject to adjustment in the same manner as such unit price, no additional units will be added to the conversion rate. In such case, the conversion rate will instead be determined in accordance with our partnership agreement and the conversion rate as adjusted will not exceed 8.6957 common units per Series A Preferred Unit, which is equal to the $25.00 liquidation preference, divided by 50% of the closing sale price of our common units on May 5, 2015.

In addition, you will have no additional rights upon a fundamental change, other than the right to convert the Series A Preferred Units into our common units plus any additional units as described above. Common units you receive upon a fundamental change may be worth less than the liquidation preference per Series A Preferred Unit.

Our obligation to satisfy the additional units requirement could be considered a penalty, in which case the enforceability thereof would be subject to general principles of reasonableness and equitable remedies.

In some limited circumstances, we may not have reserved a sufficient number of our common units to issue the full amount of common units issuable upon conversion following a fundamental change.

Some significant restructuring transactions may not constitute a fundamental change but may nevertheless result in holders of the Series A Preferred Units losing option time value.

Upon the occurrence of a fundamental change, holders will have certain rights as described in our partnership agreement. However, these provisions will not afford protection to holders of Series A Preferred Units in the event of other transactions that could adversely affect the value of the Series A Preferred Units. For example, transactions such as leveraged recapitalizations, refinancings, restructurings, or acquisitions initiated by us may not constitute a fundamental change. In the event of any such transaction, holders would not have the same protection afforded in the event of a fundamental change, even though each of these transactions could increase the amount of our indebtedness, or otherwise adversely affect our capital structure or any credit ratings, thereby adversely affecting the holders of Series A Preferred Units.

55

Upon a conversion in connection with a fundamental change, you may receive consideration worth less than the $25.00 liquidation preference per Series A Preferred Unit, plus any accumulated and unpaid distributions thereon.

If a “fundamental change” as described in our partnership agreement occurs and regardless of the price paid (or deemed paid) per common unit in such fundamental change, then holders of the Series A Preferred Units will have the right to convert their units at an adjusted conversion rate that is designed to increase the value of the common units deliverable upon conversion of each Series A Preferred Unit to the $25.00 liquidation preference per Series A Preferred Unit, plus any accumulated and unpaid distributions thereon. However, if the price paid (or deemed paid) in such fundamental change is less than $2.875 per unit (50% of the closing sale price of our common units on May 5, 2015), holders will receive a number of common units worth less than the $25.00 liquidation preference per Series A Preferred Unit, plus any accumulated and unpaid distributions thereon. You will have no claim against us for the difference between the value of the consideration you receive upon a conversion in connection with a fundamental change and the $25.00 liquidation preference per Series A Preferred Unit, plus any accumulated and unpaid distributions thereon.

You will have no rights with respect to the common units underlying your Series A Preferred Units until you convert your Series A Preferred Units, but you may be adversely affected by certain changes made with respect to our common units.

You will have no rights with respect to our common units underlying your Series A Preferred Units, including voting rights, rights to respond to common unit tender offers, if any, and rights to receive distributions or other distributions on our common units, if any (in each case, other than through a conversion rate adjustment), prior to the conversion date with respect to a conversion of your Series A Preferred Units, but your investment in our Series A Preferred Units may be negatively affected by these events. Upon conversion, you will be entitled to exercise the rights of a holder of common units only as to matters for which the relevant record date occurs on or after the conversion date. For example, in the event that an amendment is proposed to our partnership agreement, as amended, requiring unitholder approval and the record date for determining the unitholders of record entitled to vote on the amendment occurs prior to the conversion date, you will not be entitled to vote on the amendment, although you will nevertheless be subject to any changes in the powers, preferences or special rights of our common units.

Future issuances of preferred units may adversely affect the market price for our common units.

Additional issuances and sales of preferred units, or the perception that such issuances and sales could occur, may cause prevailing market prices for our common units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

The increased conversion rate triggered by a fundamental change could discourage a potential acquiror.

The increased conversion rate triggered by a fundamental change, as described in our partnership agreement, could discourage a potential acquiror, including potential acquirors that otherwise seek a transaction with us that would be attractive to you.

We may be unable to redeem the Series A Preferred Units on the term redemption date.

We are required to redeem all of the Series A Preferred Units on July 15, 2022 (“term redemption date”), at a redemption price equal to the liquidation preference of $25.00 per Series A Preferred Unit plus an amount equal to accumulated but unpaid distributions thereon (whether or not earned or declared but excluding interest thereon) up to (but excluding) the term redemption date. We may not have the funds to fulfill these obligations or the ability to refinance these obligations. If at that time other arrangements prohibit us from redeeming the Series A Preferred Units, we could try to obtain waivers of such prohibitions from the lenders and holders under those arrangements, or we could attempt to refinance the borrowings that contain the restrictions. If we could not obtain the waivers or refinance these borrowings, we would be unable to redeem the Series A Preferred Units.

56

The Internal Revenue Service could challenge our treatment of the holders of Series A Preferred Units as partners for tax purposes, and if such challenge were sustained, certain holders of Series A Preferred Units could be adversely impacted.

The treatment of the holders of Series A Preferred Units as partners for tax purposes is uncertain. Because the Series A Preferred Units have certain features, including mandatory redemption, that are more characteristic of debt than equity, the IRS may disagree with our treatment of the Series A Preferred Units as equity for tax purposes, and no assurance can be given that our treatment will be sustained. If the IRS were to successfully characterize the Series A Preferred Units as indebtedness for tax purposes, certain unitholders may be subject to additional withholding and reporting requirements. Holders of Series A Preferred Units are encouraged to consult their tax advisors regarding the tax consequences applicable to the recharacterization of the Series A Preferred Units as indebtedness for tax purposes.

Treatment of distributions on our Series A Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of our Series A Preferred Units than the holders of our common units.

The tax treatment of distributions on our Series A Preferred Units is uncertain. We will treat the holders of Series A Preferred Units as partners for tax purposes and will treat distributions on the Series A Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Series A Preferred Units as ordinary income. Although a holder of Series A Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions on a quarterly basis. Otherwise, the holders of Series A Preferred Units are generally neither anticipated to share in our items of income, gain, loss or deduction, nor be allocated any share of our nonrecourse liabilities. If the Series A Preferred Units were treated as indebtedness for tax purposes, rather than as guaranteed payments for the use of capital, distributions likely would be treated as payments of interest by us to the holders of Series A Preferred Units.

In general, you may only convert your Series A Preferred Units to common units on four specified dates each year.

You may only convert your Series A Preferred Units to common units on January 1, April 1, July 1 and October 1 of each year, subject to certain special conversion rights in connection with a fundamental change. As a result, your ability to convert your Series A Preferred Units to common units will be limited, and you may not be able to convert your Series A Preferred Units to common units at times you might otherwise desire to do so. The trading price of our common units fluctuates daily and, on the relevant conversion dates, our trading price may not be at a level that makes such conversion desirable to you.

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

57

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 May 11, 2015.

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

58

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	Amendment No. 1 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	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.	8-K	001-35809	3.1	4/30/2015
3.5	Certificate of Formation of New Source Energy GP, LLC	S-1	333-185754	3.4	1/11/2013
3.6	Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC	8-K	001-35809	3.2	2/15/2013
3.7	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
3.8	Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC	8-K	001-35809	3.2	4/30/2015
10.1	First Loan Modification Agreement, dated March 13, 2015, by and among Erick Flowback Services, LLC, Rod’s Production Services, L.L.C., Mark Snodgrass, Brian Austin, MidCentral Energy Partners L.P. and Bank 7	8-K	001-35809	10.1	3/19/2015
10.2	Letter Agreement, dated April 8, 2015, by and among New Source Energy Partners L.P., Bank of Montreal, as administrative agent, and the lenders party thereto	8-K	001-35809	10.1	4/10/2015
10.3	Seventh Amendment to Credit Agreement dated as of April 27, 2015 among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent, and the other lenders party thereto	8-K	001-35809	10.2	4/30/2015
10.4	Purchase Agreement, dated as of April 27, 2015 among Deylau, LLC, 2100 Energy LLC, and New Source Energy Partners L.P.	8-K	001-35809	10.1	4/30/2015
10.5	Exchange Agreement dated April 27, 2015 by and between New Source Energy Partners L.P. and New Source Energy GP, LLC	8-K	001-35809	10.3	4/30/2015
10.6	Eighth Amendment to Credit Agreement dated as of May 4, 2015 among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent, and the other lenders party thereto	8-K	001-35809	10.1	5/4/2015
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					*

59

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	*

60