New Source Energy Partners (NSLP) 10-Q 2015 Q2 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 June 30, 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 þ 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 August 3, 2015, the registrant had 16,525,736 common units and 2,205,000 subordinated units outstanding.

NEW SOURCE ENERGY PARTNERS L.P.

Form 10-Q

Quarter Ended June 30, 2015

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)	5
		Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	5
		Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014	7
		Condensed Consolidated Statement of Unitholders' Equity for the six months ended June 30, 2015	8
		Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	9
		Notes to Condensed Consolidated Financial Statements	11
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	37
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	54
	Item 4.	Controls and Procedures	56
PART II – OTHER INFORMATION
	Item 1.	Legal Proceedings	58
	Item 1A.	Risk Factors	59
	Item 6.	Exhibits	61

2

CERTAIN DEFINED TERMS

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

• "2100 Energy" refers to 2100 Energy LLC;

• "Deylau" refers to Deylau, LLC;

• "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, "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") and “Risk Factors” in Item 1A of Part II of the Partnership’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2015.

4

PART I: Financial Information

ITEM 1. Financial Statements

New Source Energy Partners L.P. Condensed Consolidated Balance Sheets (Unaudited)
	June 30, 2015			December 31, 2014
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash	$	5,734		$	5,504
Restricted cash	588			350
Accounts receivable, net	14,953			31,919
Accounts receivable-related parties, net	6,712			4,946
Derivative contracts	1,937			8,248
Inventory	3,530			4,236
Prepaid expenses	4,565			2,011
Other current assets	722			478
Total current assets	38,741			57,692
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	333,196			332,413
Less: Accumulated depreciation, depletion, amortization, and impairment	(237,981		)	(153,734		)
Total oil and natural gas properties, net	95,215			178,679
Property and equipment, net	68,418			68,886
Intangible assets, net	—			56,377
Goodwill	—			9,315
Derivative contracts	3			1,818
Other assets	2,381			2,779
Total assets	$	204,758		$	375,546

5

New Source Energy Partners L.P. Condensed Consolidated Balance Sheets - continued (Unaudited)
	June 30, 2015			December 31, 2014
	(in thousands, except unit amounts)
LIABILITIES, REDEEMABLE PREFERRED UNITS AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	17,999		$	15,326
Accounts payable-related parties	1,346			2,318
Factoring payable	5,098			13,152
Contingent consideration payable	21,968			11,572
Current portion of long-term debt	19,458			11,825
Other current liabilities	117			113
Total current liabilities	65,986			54,306
Long-term debt	49,602			95,218
Contingent consideration payable	—			10,801
Asset retirement obligations	3,697			3,568
Other liabilities	237			339
Total liabilities	119,522			164,232
Commitments and contingencies (Note 14)
Series A Cumulative Convertible Redeemable Preferred Units (1,930,000 units issued and outstanding at June 30, 2015)	44,629			—
Unitholders' equity:
Common units (16,525,736 units issued and outstanding at June 30, 2015 and 16,160,381 units issued and outstanding at December 31, 2014)	76,291			231,510
Common units held in escrow	(3,734		)	(6,955		)
Subordinated units (2,205,000 units issued and outstanding at June 30, 2015 and December 31, 2014)	(49,370		)	(28,717		)
General partner's units (none issued and outstanding at June 30, 2015 and 155,102 units issued and outstanding at December 31, 2014)	—			(1,944		)
Total New Source Energy Partners L.P. unitholders' equity	23,187			193,894
Noncontrolling interest	17,420			17,420
Total unitholders' equity	40,607			211,314
Total liabilities, redeemable preferred units and unitholders' equity	$	204,758		$	375,546

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

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 Six Months Ended June 30, 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	210,253	4,322			—	—			—		—			—		4,322
Distributions to unitholders	—	(6,580		)	—	—			—		(31		)	—		(6,611		)
General partner unit conversion to common units	155,102	(2,445		)	—	—			(155,102	)	2,445			—		—
Distributions on Series A Preferred Units	—	(871		)	—	(117		)	—		—			—		(988		)
Accretion of discount on Series A Preferred Units	—	(154		)	—	(21		)	—		—			—		(175		)
Net loss	—	(146,043		)	—	(20,515		)	—		(470		)	—		(167,028		)
Balance, June 30, 2015	16,525,736	$	72,557		2,205,000	$	(49,370	)	—		$	—		$	17,420	$	40,607

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)
	Six Months Ended June 30,
	2015			2014
	(in thousands)
Cash Flows from Operating Activities:
Net (loss) income	$	(167,028	)	$	54
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	18,346			19,567
Impairment	142,808			—
Accretion	133			143
Amortization of deferred loan costs	619			292
Write-off of deferred loan costs	332			—
Equity-based compensation	4,322			644
Change in fair value of contingent consideration	—			(912		)
Gain on investment in acquired business	—			(2,298		)
(Gain) loss on derivative contracts, net	(157		)	4,528
Cash received (paid) on settlement of derivative contracts	8,339			(3,412		)
Changes in operating assets and liabilities:
Accounts receivable	15,121			(3,045		)
Inventory	(2,351		)	—
Other current assets and other assets	(836		)	(1,493		)
Accounts payable and accrued liabilities	(3,094		)	620
Net cash provided by operating activities	16,554			14,688
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	—			(63,446		)
Additions to oil and natural gas properties	(941		)	(18,218		)
Additions to other property and equipment	(5,380		)	(2,991		)
Net cash used in investing activities	(6,321		)	(84,655		)
Cash Flows from Financing Activities:
Proceeds from issuance of Series A Preferred Units, net	44,454			—
Proceeds from borrowings	9,163			14,934
Payments on borrowings	(48,575		)	(5,648		)
Deposit for financing insurance	(380		)	—
Bank overdraft	—			1,838
Proceeds from financing	—			808
Proceeds from borrowings, net - related party	—			300
Payments for deferred loan costs	—			(437		)
Payments on factoring payable, net	(8,054		)	(1,583		)
Proceeds from sales of common units, net of offering costs	—			76,191
Payments of offering costs	—			(100		)
Distribution to unitholders	(6,611		)	(15,259		)
Net cash (used in) provided by financing activities	(10,003		)	71,044
Net change in cash and cash equivalents	230			1,077
Cash and cash equivalents, beginning of period	5,504			7,291
Cash and cash equivalents, end of period	$	5,734		$	8,368

9

New Source Energy Partners L.P.  Condensed Consolidated Statements of Cash Flows - continued (Unaudited)
Supplemental Cash Flow Information:
Cash paid for interest	$	2,105		$	1,859
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation	$	—		$	189
Decrease in accrued capital expenditures	$	(936	)	$	(1,457	)
Common units issued in connection with acquisitions	$	—		$	(46,239	)
Factoring payables assumed in connection with acquisitions	$	—		$	15,840
Acquisition of property and equipment by financing	$	1,200		$	2,725
Distributions payable on Series A Preferred Units	$	988		$	—
Accretion of discount on Series A Preferred Units	$	175		$	—
Debt assumed in connection with acquisitions	$	—		$	17,571

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

10

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.

Liquidity. As shown in the accompanying financial statements, the Partnership has incurred losses and has a working capital deficit at June 30, 2015. The Partnership anticipates it will continue to generate losses from operations and that cash flows may not be sufficient to cover its operating expenses, capital needs or additional debt payments resulting from the violation of debt covenants. The Partnership's ability to continue as a going concern depends on its ability to execute its business plan. However, our current cash position and our ability to access additional capital may limit our available opportunities and may not provide sufficient cash for operations, capital requirements or debt service. As we have violated debt covenants on certain of our oilfield service related debt, as discussed in Note 3 "Debt," it is possible that we will have to pay amounts outstanding sooner than anticipated based on the original maturity. Additionally, we anticipate that the borrowing base on our senior secured revolving credit facility (the "credit facility") will be further reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. These factors raise substantial doubt about the Company’s ability to continue as a going concern.

11

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Management is actively pursuing additional sources of capital. We believe that we will be successful in securing any funds necessary to continue as a going concern. The Partnership, however, is dependent upon its ability to secure equity or debt financing or monetize certain of its oilfield services assets and there are no assurances that the Partnership will be successful in such endeavors. The financial statements do not include any adjustments that might result from the outcome of any uncertainty as to the Partnership’s ability to continue as a going concern. The financial statements also do not include any adjustments relating to the recoverability and classification of recorded asset amounts, or amounts and classifications of liabilities that might be necessary should the Partnership be unable to continue as a going concern.

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

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

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

In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which changes the presentation of debt issuance costs. ASU 2015-03 requires debt issuance costs related to a recognized debt liability to be presented as a direct reduction from the carrying amount of the related debt. The new standard does not change the recognition and measurement of debt issuance costs. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. Upon adoption of the guidance, assets and liabilities will decrease in the consolidated balance sheet with no impact to the consolidated statement of operations.

In April 2015, the FASB issued ASU No. 2015-06, “Earnings Per Share (Topic 260): Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions (a consensus of the FASB Emerging Issues Task Force),” which applies to master limited partnerships that receive net assets through a dropdown transaction. ASU 2015-06 specifies that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two-class method also are required. ASU 2015-06 is effective for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years and will be applied retrospectively. Earlier application is permitted. We are currently evaluating the effect, if any, this updated standard will have.

12

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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 11 "Related Party Transactions." In 2014, we also acquired working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma to expand the Partnership's exploration and production segment.

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

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

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

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

__________

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

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

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

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(Unaudited)

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

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

__________

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

(2) The Partnership agreed to provide additional common units in the second quarter of 2015 to the former owners of MCCS based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See Note 14 "Commitments and Contingencies" for additional discussion on the MCCS Contingent Consideration.

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

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

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

__________

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

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

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

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

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

__________

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

(2) The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units were issued into escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition and are excluded from consideration based on the future service requirement for vesting. See Note 8 "Equity" for additional discussion of phantom units.

(3) The Partnership agreed to provide additional consideration in the second quarter of 2015 to the former owners of EFS and RPS based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million at the acquisition date through the use of a probability analysis. See Note 14 "Commitments and Contingencies" for additional discussion of the EFS/RPS Contingent Consideration.

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

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

__________

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

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(Unaudited)

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

Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the three and six months ended June 30, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013, which was the beginning of the earliest period presented at the time of the acquisition. The pro forma combined results of operations for the three and six months ended June 30, 2014 have been prepared by adjusting the historical results of the Partnership to include the historical results of the 2014 Material Acquisitions through the dates of acquisition and estimates of the effect of these transactions on the combined results. In addition, pro forma adjustments have been made assuming the units issued as consideration for these acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund the Services Acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

	Three Months Ended June 30, 2014		Six Months Ended June 30, 2014
	(in thousands, except per unit amounts)
Revenue	$	55,881	$	116,166
Net income attributable to New Source Energy Partners L.P. (1)	$	4,079	$	6,186
Net income per common unit (1):
Basic	$	0.24	$	0.37
Diluted	$	0.24	$	0.37

__________

(1) Excludes $23.9 million of acquisition costs and transaction bonuses paid to EFS and RPS employees that were included in the historical results of the Partnership, EFS or RPS.

The amount of revenues and operating income included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2014 generated by the 2014 Material Acquisitions are shown in the table below. The operating income attributable to the CEU Acquisition represents the excess of revenues over direct operating expenses and does not reflect certain expenses, such as general and administrative; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. Direct operating expenses include lease operating expenses and production and other taxes for the CEU Acquisition.

	Three Months Ended June 30, 2014		Six Months Ended June 30, 2014
	(in thousands)
Revenue	$	3,054	$	4,937
Excess of revenue over direct operating expenses	$	1,077	$	2,196

Acquisition expense for the 2014 Material Acquisitions of $1.3 million was included in general and administrative expenses in the accompanying unaudited statements of operations for both the three and six months ended June 30, 2014.

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

3.  Debt

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

	June 30, 2015		December 31, 2014
Credit facility	$	49,000	$	83,000
Notes payable	17,693		20,424
Line of credit	2,367		3,619
Total debt	69,060		107,043
Less: current maturities of long-term debt	19,458		11,825
Long-term debt	$	49,602	$	95,218

Senior Secured Revolving Credit Facility

The Partnership has a credit facility that is available to be drawn on subject to limitations based on its terms and certain financial covenants described below. As of June 30, 2015, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of its subsidiaries. The credit facility matures in February 2017.

In the second quarter of 2015, the credit facility was amended to, among other things, provide for 2100 Energy’s acquisition of a portion of Deylau's limited liability company interest in our general partner in April 2015, which is discussed further in Note 11 "Related Party Transactions," increase certain of the collateral requirements, permit us to dispose all of our limited liability company interest in MCE GP upon the satisfaction of various conditions as described in Note 11 "Related Party Transactions," permit the Partnership to make cash distributions up to $6.0 million per year to holders of our Series A Preferred Units and impose certain hedging requirements for our oil and natural gas assets upon our unwinding of any current hedges prior to the October 2015 redetermination date.

Additionally, the credit facility contains various covenants and restrictive provisions that, among other things, limit the ability of the Partnership to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. The credit facility permits the Partnership to make distributions to its common unit holders in an amount not to exceed "available cash" (as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership) if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed 90%. As of June 30, 2015, the Partnership was in compliance with all covenants under the credit facility.

Our credit facility is subject to a borrowing base which is generally set by the bank semi-annually on April 1 and October 1 of each year. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. In the second quarter of 2015, our borrowing base was lowered from $90.0 million to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. On May 29, 2015, the borrowing base was reduced further to $57.0 million in response to the settlement of a portion of our derivative contracts prior to their contractual maturity. We anticipate that our borrowing base will be reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. As of June 30, 2015, the Partnership had $49.0 million in outstanding borrowings with $8.0 million of available borrowing capacity.

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(Unaudited)

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At June 30, 2015 and December 31, 2014, the average annual interest rate on borrowings outstanding under the credit facility was 3.19% and 3.44%, respectively.

Notes Payable

MCES Notes Payable. The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. The notes range from 12 to 60 months in duration with maturity dates from August 2015 through March 2019 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. Certain of these notes contain a requirement for MCES to maintain a fixed charge ratio of not less than 1.25 to 1.0. As of June 30, 2015, MCES was not in compliance with the covenants under certain of these notes and, as such, is in default on these notes. As a result, the outstanding balances for these notes were reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. The Partnership had $5.5 million outstanding, of which $4.9 million was current, under the MCES notes payable as of June 30, 2015.

EFS Loan Agreement. In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on EFS' existing notes payable, which were originally set to mature on June 26, 2015. In March 2015, we refinanced EFS' notes payable to extend the maturity date to March 2018. The balance on the note payable at June 30, 2015 was $10.8 million.

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

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

MCES Promissory Notes. On January 9, 2015 and February 24, 2015, MCES issued promissory notes totaling approximately $1.4 million, to acquire land from entities owned 50% by Mr. Kos and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner. Both promissory notes bear interest at prime plus one percent and are payable, including all accrued interest, on December 31, 2015. No payments are due prior to maturity. See Note 11 "Related Party Transactions" for additional discussion of the related party land transactions.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. In June 2015, the line of credit was lowered to a maximum of $3.0 million with the borrowing base determined based on MCES' eligible accounts receivable. Our monthly interest only payments accrue at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at June 30, 2015. The line of credit matures in September 2015 and is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. The outstanding balance was $2.4 million at June 30, 2015 and was reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015.

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

The line of credit contains a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of June 30, 2015, MCES was not in compliance with this covenant under the line of credit, which is considered an event of default under the terms of the agreement.

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 $5.1 million as of June 30, 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.

At June 30, 2015, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

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

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(Unaudited)

The following tables present our derivative instruments outstanding as of June 30, 2015:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
July 2015 - September 2015	9,317	$	80.00	$	93.25
October 2015 - December 2015	26,220	$	55.00	$	67.00
January 2016 - March 2016	25,935	$	55.00	$	67.00
April 2016 - December 2016	45,375	$	55.00	$	69.20

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
July 2015 - December 2015	9,200	$	77.50	$	92.50	$	102.60

Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
July 2015 - September 2015	10,777	$	88.90

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
July 2015 - September 2015	325,114	$	4.00	$	4.32
October 2015 - December 2015	340,400	$	2.85	$	3.46
January 2016 - March 2016	336,700	$	2.85	$	3.46
April 2016 - December 2016	1,017,500	$	2.85	$	3.40

Natural gas put options	Volumes (MMBtu)	Floor Price
July 2015 - December 2015	210,876	$	3.50

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
July 2015 - September 2015	194,461	$	4.25

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
July 2015 - September 2015	20,782	$	75.18

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

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(Unaudited)

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

June 30, 2015	Gross Amounts of Recognized Assets and Liabilities			Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,942		$	(5	)	$	1,937
Commodity derivatives - long-term assets	3			—			3
Total	$	1,945		$	(5	)	$	1,940
Liabilities:
Commodity derivatives - current liabilities	$	(5	)	$	5		$	—
Commodity derivatives - long-term liabilities (1)	(56		)	—			(56		)
Total	$	(61	)	$	5		$	(56	)

__________

(1)    Commodity derivatives - long-term liabilities are included in other liabilities on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015.

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

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

The following table presents cash settlements on our derivative contracts as included in (loss) gain on derivative contracts, net in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015 and 2014 (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Cash receipts (payments) upon settlement (1)	$	6,000	$	(983	)	$	8,339	$	(3,412	)

__________

(1) Cash receipts upon settlement of derivative contracts for the three and six months ended June 30, 2015 includes $3.9 million related to the settlement of certain derivative contracts with contract maturities subsequent to the period in which they were settled ("early settlements"). In the second quarter of 2015, we monetized certain of our derivative contracts for the periods October 2015 through December 2015 and calendar year 2016.

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(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 prior to the second quarter of 2014 were based upon quotes obtained from counterparties to the derivative contracts. See discussion below regarding transfer of these derivative contracts from Level 3 to Level 2. These values were reviewed internally for reasonableness. The significant unobservable inputs used in the fair value measurement of our natural gas and NGL put options and NGL fixed price swaps were the estimated probability of exercise and the estimate of NGL futures prices. Significant increases (decreases) in the probability of exercise and NGL futures prices could result in a significantly higher (lower) fair value measurement. 

Contingent consideration. As discussed in Note 14 "Commitments and Contingencies," the Partnership agreed to pay additional consideration on certain acquisitions if specific target metrics were met. The fair value of the contingent consideration resulting from these acquisitions was based on the present value of estimated future payments, using various inputs, including forecasted EBITDA metrics and the probability that targets for additional payout will be met. Significant increases (decreases) in the probability of meeting target payout levels result in a significantly higher (lower) fair value measurement. 

22

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

June 30, 2015	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)		Unobservable Inputs (Level 3)		Total Carrying Value
Oil and natural gas collars	$	—	$	667	$	—	$	667
Natural gas put options	—		140		—		140
Oil, natural gas and NGL fixed price swaps	—		1,077		—		1,077
Total	$	—	$	1,884	$	—	$	1,884

23

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

	Three Months Ended   June 30, 2014			Six Months Ended   June 30, 2014
Beginning balance	$	(2,843	)	$	(2,517	)
Loss on derivative contracts	—			(2,432		)
Transfers out (1)	2,843			2,843
Cash received upon settlement	—			2,106
Ending balance (1)	$	—		$	—
Unrealized losses included in earnings relating to derivatives held at period end	$	—		$	—

__________

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

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

Fair Value of Financial Instruments

Credit Facility. The carrying amount of the credit facility of $49.0 million and $83.0 million as of June 30, 2015 and December 31, 2014, respectively, approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings.

Notes Payable. The carrying value of our notes payable of $17.7 million and $20.4 million at June 30, 2015 and December 31, 2014 approximated fair value based on rates applicable to similar instruments. 

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

Fair Value on a Non-Recurring Basis

The Partnership performs valuations on a non-recurring basis primarily as it relates to the consideration, assets acquired and liabilities assumed related to acquisitions and, as required, for impairment analysis of goodwill, intangible assets and property, plant and equipment. See Note 2 "Acquisitions," Note 7 "Goodwill and Intangible Assets," Note 12 "Property, Plant and Equipment" and Note 14 "Commitments and Contingencies" for discussion of these valuations.

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New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

7. Goodwill and Intangible Assets

Goodwill. Goodwill represents the estimated future economic benefits arising from other assets acquired in business combinations that could not be individually identified and separately recognized. See Note 2 "Acquisitions" for discussion of our business acquisitions. Goodwill has been allocated to reporting units within the oilfield services segment and is not deductible for tax purposes. A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands):

Goodwill at December 31, 2014	$	9,315
Impairment	(9,315		)
Goodwill at June 30, 2015	$	—

The goodwill balance as of December 31, 2014 is associated with the acquisition of EFS. As of April 1, 2015, the Partnership performed the annual impairment test on goodwill. Primarily as a result of a decrease in projected revenue of EFS, which is a significant component in determining the fair value of this reporting unit, the carrying value of EFS exceeded its fair value. We performed step two of the impairment test to determine the amount of goodwill that was impaired. Based on this assessment, it was determined that goodwill was fully impaired and $9.3 million was recorded as impairment and included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015.

Intangible Assets. Intangible assets were identified in the acquisitions during 2014. See Note 2 "Acquisitions" for discussion of our business acquisitions. Intangible assets are amortized over the expected cash flow period for customer relationships and over the agreement period for the non-compete agreements. Amortization expense for the six months ended June 30, 2015 was $5.2 million. There was no amortization expense for the three months ended June 30, 2015 as a result of the impairment of our intangible assets, as discussed below. Amortization expense for the three and six months ended June 30, 2014 was $ 3.1 million and $6.2 million, respectively. A reconciliation of the Partnership's intangible assets for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands):

Intangible assets, net, at December 31, 2014	$	56,377
Amortization expense	(5,166		)
Impairment	(51,211		)
Intangible assets, net, at June 30, 2015	$	—

In the second quarter of 2015, the Partnership deemed the continued significant decline in commodity prices and the related impact or estimated impact to our oilfield services business to be a triggering event for the purpose of evaluating its intangible assets for impairment. Accordingly, impairment tests were performed by calculating the estimated future cash flows to be generated by the respective revenue generating asset groups. The undiscounted future cash flows were less than the respective revenue generating asset groups' carrying value for the intangible assets from the Services Acquisition. Based on the discounted cash flows of the asset group, an impairment of these intangible assets, or approximately $51.2 million, was recorded and is included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015.

8.  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.

25

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. We also granted the underwriters a 30-day overallotment option to purchase up to an additional 264,000 Series A Preferred Units. On June 5, 2015, the underwriters partially exercised the overallotment option and we issued an additional 170,000 Series A Preferred Units for approximately $4.0 million in additional proceeds.  See Note 9 "Cumulative Convertible Preferred Units" for further discussion of our Series A Preferred Units.

Distributions

Distributions are declared and distributed within 45 days following the end of each quarter. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the six months ended June 30, 2015 and 2014, are shown in the following table (in thousands, except per unit amounts):

Distributions	Declaration Date	Payable Date	Distribution per Unit		Common Units		Subordinated Units		General Partner Units		Total
2015
First Quarter	May 8, 2015	May 15, 2015	$	0.20	$	3,312	$	—	$	—	$	3,312
Second Quarter	N/A	N/A	$	—	$	—	$	—	$	—	$	—
2014
First Quarter	April 21, 2014	May 15, 2014	$	0.580	$	7,852	$	1,279	$	90	$	9,221
Second Quarter	July 21, 2014	August 15, 2014	$	0.585	$	9,025	$	1,290	$	91	$	10,406

Pursuant to our partnership agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. No such incentive distributions were made to our general partner as quarterly distributions declared by the board of directors for the first or second quarters of 2015 and 2014 did not exceed the specified targets. We suspended common unit distributions in July 2015 for the second quarter of 2015 and made distributions per common unit of $0.20 in the first quarter of 2015. These distributions were below the minimum quarterly distribution ("MQD") established by our partnership agreement. Subordinated units are not entitled to receive distributions until the common units receive an amount equal to the MQD and the cumulative arrearages of approximately $14.0 million at June 30, 2015. The subordination period ends on the first business day after all units have received the MQD for each of four consecutive quarters ending on or after December 31, 2015, or as otherwise provided for under the partnership agreement.

Noncontrolling Interest

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

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

26

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

				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 six months of 2015 or 2014.

Equity Compensation

We may grant awards of the Partnership's common units to employees under the Partnership's Long-Term Incentive Plan ("LTIP") or Fair Market Value Purchase Plan ("FMVPP"). In the first quarter of 2015, we granted 242,753 common units under the LTIP. Of these common units granted, 219,439 vested immediately or had accelerated vesting, which resulted in $1.5 million of equity-based compensation expense and is included in the accompanying unaudited condensed consolidated statement of operations for the six months ended June 30, 2015.

Phantom Units. In conjunction with the Services Acquisition, the Partnership granted 432,038 phantom units, which represent the right to receive common units or cash equal to the value of the associated common units, to employees of EFS and RPS under the FMVPP. The phantom units vest over a period not to exceed 2 years. Although the phantom unit grants may be settled in either common units or cash at the holder's election, the settlement of the phantom units upon vesting will be made from a transfer or sale of the associated common units that were issued to an escrow account, reflected as contra equity on the accompanying unaudited condensed consolidated balance sheets, in conjunction with the Services Acquisition. As a result, the 401,171 phantom units valued at $10.1 million with a service requirement were measured at fair market value of the Partnership’s common units on the grant date and are being expensed over the vesting period in accordance with accounting guidance for equity compensation. In the first quarter of 2015, the vesting of certain phantom unit awards was accelerated resulting in $0.9 million of expense. There were no accelerated vestings in the second quarter of 2015.

For the three and six months ended June 30, 2015, the Partnership recorded total equity-based compensation expense of $0.4 million and $4.3 million, respectively, compared to $0.4 million and $0.6 million for the same periods in 2014. Equity-based compensation expense for the 2015 period includes amounts related to awards granted in the second half of 2014 and first quarter of 2015, including amounts for awards in which vesting was accelerated.

9. Cumulative Convertible Preferred Units

On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. In addition, we granted the underwriters a 30-day overallotment option to purchase up to an additional 264,000 Series A Preferred Units. On June 5, 2015, the underwriters partially exercised the overallotment option and purchased an additional 170,000 Series A Preferred Units. Holders of our Series A Preferred Units are entitled to receive quarterly cash distributions at the rate of 11.0% per annum. The Series A Preferred Units are convertible into common units on any January 1, April 1, July 1 or October 1 by the holder at the initial conversion rate of 3.7821 common units per Series A Preferred Unit. We may elect to convert the Series A Preferred Units into our common units on or after July 15, 2018 in certain circumstances. We will redeem all of the Series A Preferred Units on July 15, 2022 at a redemption price equal to the liquidation preference of $25.00 plus an amount equal to accumulated but unpaid distributions thereon. If we do not redeem the Series A Preferred Units on July 15, 2022, then the per annum distribution rate will increase by an additional 2.0% per month until such redemption, up to a maximum rate per annum of 20.0%. The Series A Preferred Units rank senior to our common units with respect to rights upon the liquidation, dissolution or winding up of the Partnership.

27

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Holders of our Series A Preferred Units have no voting rights except in limited circumstances. So long as any Series A Preferred Units remain outstanding, we will not, without the affirmative vote or consent of the holders of at least 66 2/3% of the Series A Preferred Units outstanding at the time, voting together as a single class with all series of parity securities with similar voting rights have been conferred and are exercisable, given in person or by proxy, either in writing or at a meeting: (a) authorize or create, or increase the authorized or issued amount of, any class or series of senior securities or reclassify any of our authorized equity securities into units of senior securities, or create, authorize or issue any obligation or security convertible into or evidencing the right to purchase any senior securities; (b) consummate a spin-off prior to the earlier to occur of (i) December 31, 2016 or (ii) the first day after which 2100 Energy has caused one or a series of transactions to occur whereby one or more third parties have transferred $100 million (the “Transfer Threshold”) of oil and natural gas assets to a subsidiary of us, provided that (1) any distributions or equivalents from the sale or transfer of equity in our oilfield services subsidiaries and (2) any obligations of us that have been or will be assumed by our oilfield services subsidiaries that are being spun-off, in each case without any guarantee by or recourse to us, shall, in each case, reduce the Transfer Threshold on a dollar-for-dollar basis or (c) amend, alter or repeal the provisions of our Partnership Agreement, whether by merger, consolidation or otherwise (an “Event”), so as to materially and adversely affect any right, preference, privilege or voting power of the Series A Preferred Units; provided, however, with respect to the occurrence of any Event set forth in (c) above, so long as the Series A Preferred Units remains outstanding with the terms thereof materially unchanged, the occurrence of any such Event shall not be deemed to materially and adversely affect such rights, preferences, privileges or voting power of holders of the Series A Preferred Units and, provided further, that any increase in the amount of the authorized preferred units, including the Series A Preferred Units, or the creation or issuance of any additional Series A Preferred Units or other series of preferred units, or any increase in the amount of authorized units of such series, in each case ranking on parity with or junior to the Series A Preferred Units with respect to payment of distributions, shall not be deemed to materially and adversely affect such rights, preferences, privileges or voting powers.

We received net proceeds, including proceeds from the exercise of the underwriters' option, of approximately $44.4 million from this offering after deducting underwriting discounts of $2.9 million and estimated offering costs of $1.0 million.  We used the net proceeds from the offering to repay a portion of the indebtedness outstanding under our credit facility.

Our Series A Preferred Units are recorded as temporary equity on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015 as the units are convertible at any time at the option of the holder and become redeemable for cash on July 15, 2022. On June 18, 2015, the Partnership declared a quarterly distribution of $0.5118, prorated for the period May 9, 2015 to July 14, 2015, per Series A Preferred Unit to holders of record on July 1, 2015. These distributions, totaling $1.0 million, were subsequently paid on July 15, 2015.

10. Earnings per Unit

The Partnership’s net income (loss) is allocated to the common, subordinated and general partner unitholders in accordance with their respective ownership percentages. When applicable, we give effect to dividends declared and accretion related to the discount on our Series A Preferred Units as well as unvested units granted under the Partnership’s LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period.

We present earnings per unit regardless of whether such earnings would or could be distributed under the terms of our partnership agreement. Accordingly, the reported earnings per unit is not indicative of potential cash distributions that may be made based on historical or future earnings. Basic and diluted net income per unit is calculated by dividing net income attributable to each class of unit by the weighted average number of units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. During the three and six months ended June 30, 2015, approximately 4,074,693 and 2,048,603 weighted average common units, respectively, issuable upon conversion of our Series A Preferred Units at the initial conversion rate and LTIP awards of 33,714 and 34,873 common units, respectively, were excluded from the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of June 30, 2014. Therefore, basic and diluted earnings per unit are the same for the three and six months ended June 30, 2014.

28

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Basic and diluted earnings per unit for the three and six months ended June 30, 2015 and 2014 were computed as follows (in thousands, except per unit amounts):

	Three Months Ended   June 30, 2015						Six Months Ended   June 30, 2015
	Common Units			Subordinated Units			Common Units			Subordinated Units			General Partner (1)
Net loss attributable to common, subordinated, and general partner units	$	(97,513	)	$	(13,506	)	$	(147,068	)	$	(20,653	)	$	(470	)
Weighted average units outstanding	16,458			2,205			16,402			2,205			155
Basic and diluted loss per unit	$	(5.92	)	$	(6.12	)	$	(8.97	)	$	(9.37	)	$	(3.03	)

__________

(1)    General partner units were converted to common units effective April 27, 2015. Net loss and per unit loss reflected is the loss allocated to general partner units prior to the conversion.

	Three Months Ended   June 30, 2014						Six Months Ended   June 30, 2014
	Common Units		Subordinated Units		General Partner		Common Units		Subordinated Units			General Partner
Net income (loss)	$	1,334	$	235	$	17	$	97	$	(40	)	$	(3	)
Weighted average units outstanding	12,529		2,205		155		11,232		2,205			155
Basic and diluted income (loss) per unit	$	0.11	$	0.11	$	0.11	$	0.01	$	(0.02	)	$	(0.02	)

11. Related Party Transactions

Ownership. At April 1, 2015, the Partnership was controlled by our general partner which was owned 69.4% by Deylau, an entity controlled by Mr. Kos, 25.0% by the David J. Chernicky Trust, and 5.6% by NSEC. Mr. Chernicky was the former Chairman of the board of directors of our general partner. Mr. Kos beneficially owns approximately 6.4% of the Partnership's outstanding common units. On April 27, 2015, the Partnership entered into a purchase agreement among the Partnership, Deylau, and 2100 Energy pursuant to which Deylau transferred an 18.4% limited liability company interest in our general partner to 2100 Energy. If 2100 Energy does not cause one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, transfer $150.0 million (or, in certain circumstances, a smaller amount) in oil and natural gas assets to a subsidiary of the Partnership by December 31, 2016, the 18.4% limited liability company interest in our general partner will revert back to Deylau. Upon completion of such transfer of assets to our subsidiary, Deylau will transfer its remaining limited liability company interest in our general partner to 2100 Energy, resulting in 2100 Energy owning a 69.4% limited liability company interest in our general partner. Consideration for the transfer of oil and natural gas assets to the Partnership will be based on fair value for the assets and approved by the board of directors of our general partner. In exchange for the transfer of Deylau's limited liability company interest in our general partner (as described above), the Partnership will also transfer all of its limited liability company interest in MCE GP, the general partner of MCLP, to an entity owned, directly or indirectly, by Deylau and Signature Investments LLC, which is wholly-owned by Mr. Tourian. Following such transactions, the Partnership will own all of the equity interests in MCLP except for the general partner interest and the Class B units.

Also in April 2015, the Partnership entered into an exchange agreement with our general partner whereby our general partner eliminated the economic portion of its general partner interest in the Partnership and canceled all of its general partner units in exchange for the issuance by the Partnership of an equivalent amount of 155,102 common units. The general partner interest ceased to be an economic interest in the Partnership; however, our general partner continues to be the general partner of the Partnership.

As of June 30, 2015, Mr. Chernicky beneficially owned approximately 15.1% of the Partnership's outstanding common units. Mr. Chernicky also beneficially owns 100% of the 2,205,000 subordinated units through his control of NSEC. As a result of these ownership interests in the Partnership and his ownership of all of the membership interests in New Dominion, which operates all of the Partnership's oil and natural gas properties, transactions with New Dominion are deemed to be with a related party.

29

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

New Dominion. New Dominion is an exploration and production operator wholly owned by Mr. Chernicky. Pursuant to various development agreements with the Partnership, New Dominion is currently contracted to operate the Partnership’s existing wells. In 2014, the Partnership, along with other working interest owners, reimbursed New Dominion for our proportionate share of costs incurred to construct a gas gathering system which transports production to the gas processing plant in the Greater Golden Lane field. In return, we own a portion of such gas gathering system.

New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated was approximately $0.2 million as of June 30, 2015 and $0.4 million as of December 31, 2014, all of which is classified as a long-term liability in the accompanying unaudited condensed consolidated balance sheets.

Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the three and six months ended June 30, 2015 and 2014 (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Producing overhead and supervision charges	$	639	$	454	$	1,372	$	829
Drilling and completion supervision charges	138		39		176		48
Saltwater disposal fees	306		443		550		858
Total expenses incurred	$	1,083	$	936	$	2,098	$	1,735

Receivables from New Dominion represent amounts due primarily for sale of our oil, natural gas and NGL production. Payables due to New Dominion represent amounts owed primarily for production costs associated with production of our oil, natural gas and NGL volumes. At June 30, 2015 and December 31, 2014, the Partnership had related party receivables, net from New Dominion of $5.7 million and $3.4 million, respectively. See Note 14 "Commitments and Contingencies" for discussion of litigation with our contract operator.

New Source Energy GP, LLC. Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three and six months ended June 30, 2014, the amount paid to our general partner for such reimbursements was $0.3 million and $0.6 million, respectively. These expenses are included in general and administrative expenses in the accompanying unaudited condensed consolidated statements of operations. Beginning in 2015, our general partner no longer billed us for these general and administrative costs as the Partnership began incurring these expenses directly. At June 30, 2015 and December 31, 2014, $0.4 million and $2.3 million, respectively, were due to our general partner for reimbursement and included in accounts payable - related parties in the accompanying unaudited condensed consolidated balance sheets.

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

On January 9, 2015, MCES acquired two separate parcels of land, one located in Canadian County, Oklahoma and one located in Ector County, Texas, from an entity owned 50% by Mr. Kos and 50% by Mr. Tourian for approximately $0.9 million. Additionally, on February 24, 2015, MCES acquired land located in Karnes County, Texas from an entity owned 67% by Mr. Kos and 33% by Mr. Tourian for approximately $0.5 million. The purchase price for each transaction was determined based on independent third-party appraisals for each property. In each transaction, a promissory note for the entire purchase price was issued by MCES to Mr. Kos and Mr. Tourian and is payable on December 31, 2015. See Note 3 "Debt" for additional discussion on these notes payable.

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

30

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

12. Property, Plant and Equipment

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

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

Based on the 12-month average prices of oil, natural gas and NGLs as of March, 31, 2015 and June 30, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015 and $32.9 million during the second quarter of 2015. Continued low levels or declines in oil, natural gas and NGL prices subsequent to June 30, 2015 are expected to result in additional ceiling test write downs in the third quarter of 2015 and in subsequent periods. The amount of any future impairment is difficult to predict, and will primarily depend on oil, natural gas and NGL prices during these periods.

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

	June 30, 2015			December 31, 2014
Vehicles and transportation equipment	$	15,970		$	15,891
Machinery and equipment	51,680			44,441
Office furniture and equipment	2,036			1,069
Iron	13,476			12,258
Total	83,162			73,659
Less: accumulated depreciation and impairment	(15,945		)	(4,773		)
	67,217			68,886
Land	1,201			—
Property and equipment, net	$	68,418		$	68,886

Due to the continued depressed commodity environment and the impact on the demand for oilfield services, the Partnership analyzed its oilfield services equipment for impairment in the second quarter of 2015. Based on current utilization rates, the decline in rental rates and consideration of sales prices for similar oilfield services equipment, the Partnership recorded an impairment on its oilfield services equipment of approximately $6.3 million for the three and six months ended June 30, 2015.

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New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

13.  Asset Retirement Obligations

A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the period from December 31, 2014 to June 30, 2015 is as follows (in thousands):

Asset retirement obligation at January 1, 2015	$	3,681
Liability incurred upon acquiring and drilling wells	—
Accretion	133
Asset retirement obligation at June 30, 2015	3,814
Less current portion	117
Asset retirement obligations, net of current	$	3,697

14. Commitments and Contingencies

Commitments

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

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

Contingent Consideration

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

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

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New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

EFS/RPS. The former owners of EFS and RPS were entitled to receive additional consideration in the form of cash and common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments. The terms of the contribution agreement provide that the additional consideration is to be paid approximately 50% in cash and approximately 50% in common units, consistent with the initial consideration for the Services Acquisition. However, the former owners can elect to receive up to 100% of the payout in common units. The EFS/RPS Contingent Consideration was valued at $22.0 million as of the acquisition date and was included in the consideration for the Services Acquisition. The fair value of the EFS/RPS Contingent Consideration was approximately $23.3 million as of December 31, 2014.

In March 2015, we entered into an agreement with the former owners that allows for the payment of the cash portion of the EFS/RPS Contingent Consideration to be extended to May 2016. Beginning in June 2015, interest payments at an annual rate of 5.5% are due monthly with principal and any unpaid interest due May 1, 2016. A receivable of approximately $1.0 million due from the former owners has been offset against the contingent consideration obligation. Additionally, the contingent consideration obligation was reduced for certain costs incurred by the Partnership, as provided for in the purchase agreement. At June 30, 2015, the net contingent consideration was approximately $22.0 million. As a result of ongoing discussions with the former owners, we have not yet issued common units to satisfy the equity portion of the contingent consideration obligation.

Legal Matters

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

On February 23, 2015, the defendants filed several motions to dismiss the claims raised in the plaintiffs’ petition, including motions by the Partnership and our general partner that (i) the defendants' claims fail to state a claim; (ii) the defendants' claims are time barred by statues of limitations; and (iii) Tulsa County is an improper venue. A hearing on certain of the motions to dismiss was held on August 5, 2015 with another hearing scheduled for September 11, 2015. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action.

In addition to the proceeding described above, on January 29, 2015, the Partnership received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by the Partnership to NSEC. The total amount of the purported claims totaled approximately $1.9 million. During 2015, New Dominion has withheld all revenue from the Partnership's sold oil and natural gas production in satisfaction of these claims and other amounts New Dominion and its affiliates claim to be owed by the Partnership. The Partnership disputes New Dominion’s claims and related withholding of revenue, and on June 4, 2015, the Partnership amended a previously filed lawsuit against New Dominion pending in the District Court of Tulsa County, Oklahoma to add certain of New Dominion’s officers as well as David Chernicky as defendants. In the lawsuit, the Partnership seeks a temporary and permanent injunction and declaratory action and asserts breach of contract, negligence, gross negligence, willful misconduct and fraud against the various defendants. No hearing date has been set in this matter.

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

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New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

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

15. Business Segment Information

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

34

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

	Exploration and Production			Oilfield Services			Total
Three Months Ended June 30, 2015
Revenues	$	5,319		$	18,765		$	24,084
Direct operating expenses	4,092			14,637			18,729
Segment margin	1,227			4,128			5,355
Depreciation, depletion, amortization and accretion	3,620			2,438			6,058
Impairment	32,905			66,784			99,689
General and administrative expenses	2,254			4,417			6,671
Loss from operations	$	(37,552	)	$	(69,511	)	$	(107,063	)
Capital expenditures (1)	$	126		$	14		$	140
Three Months Ended June 30, 2014
Revenues	$	16,718		$	10,100		$	26,818
Direct operating expenses	5,308			5,968			11,276
Segment margin	11,410			4,132			15,542
Depreciation, depletion, amortization and accretion	6,970			3,393			10,363
General and administrative expenses	2,022			1,467			3,489
Income (loss) from operations	$	2,418		$	(728	)	$	1,690
Capital expenditures (1)	$	7,709		$	2,177		$	9,886

__________

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

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New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

	Exploration and Production			Oilfield Services			Total
Six Months Ended June 30, 2015
Revenues	$	11,886		$	50,315		$	62,201
Direct operating expenses	8,458			37,696			46,154
Segment margin	3,428			12,619			16,047
Depreciation, depletion, amortization and accretion	8,413			10,066			18,479
Impairment	76,024			66,784			142,808
General and administrative expenses	6,823			12,082			18,905
Loss from operations	$	(87,832	)	$	(76,313	)	$	(164,145	)
Capital expenditures (1)	$	1,140		$	6,117		$	7,257
At June 30, 2015
Total assets	$	111,793		$	92,965		$	204,758
Six Months Ended June 30, 2014
Revenues	$	35,569		$	18,676		$	54,245
Direct operating expenses	10,690			10,534			21,224
Segment margin	24,879			8,142			33,021
Depreciation, depletion, amortization and accretion	12,857			6,853			19,710
General and administrative expenses	5,866			3,184			9,050
Income (loss) from operations	$	6,156		$	(1,895	)	$	4,261
Capital expenditures (1)	$	18,460		$	2,991		$	21,451
At December 31, 2014
Total assets	$	199,178		$	176,368		$	375,546

__________

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

16.  Subsequent Events

Distributions. On July 29, 2015, the Partnership suspended payment of quarterly distributions on its common units.

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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 and six months ended June 30, 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, "Item 1A. Risk Factors" of the 2014 Form 10-K and “Item 1A. Risk Factors” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015. 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 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

37

• production taxes.

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, impairment, non-cash compensation expense, non-recurring transaction fees, loss (gain) on derivative contracts net of cash received (paid) on settlement of derivative contracts and other 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, Deylau, and 2100 Energy pursuant to which Deylau transferred an 18.4% limited liability company interest in our general partner to 2100 Energy. If 2100 Energy does not cause one or a series of transactions to occur whereby one or more third parties will, subject to approval by the board of directors of our general partner, transfer $150.0 million (or, in certain circumstances, a smaller amount) in oil and natural gas assets to a subsidiary of the Partnership by December 31, 2016, the 18.4% limited liability company interest in our general partner will revert back to Deylau. Upon completion of such transfer of assets to the subsidiary, Deylau will transfer its remaining limited liability company interest in our general partner to 2100 Energy, resulting in 2100 Energy owning a 69.4% limited liability company interest in our general partner. Consideration for the transfer of oil and natural gas assets to the Partnership will be based on fair value for the assets and approved by the board of directors of our general partner. In exchange for the transfer of Deylau's limited liability company interest in our general partner (as described above), the Partnership will also transfer all of its limited liability company interest in MCE GP, the general partner of MCLP, to an entity owned, directly or indirectly, by Deylau and Signature Investments LLC. Following such transactions, the Partnership will own all of the equity interests in MCLP except for the general partner interest and the Class B units.

Exchange Agreement. On April 27, 2015, the Partnership entered into an exchange agreement with our general partner whereby our general partner eliminated the economic portion of its general partner interest in the Partnership and canceled all of its general partner units in exchange for the issuance by the Partnership of an equivalent amount of 155,102 common units. The general partner interest ceased to be an economic interest in the Partnership; however, our general partner continues to be the general partner of the Partnership.

Amendments to Credit Facility. In the second quarter of 2015, the credit facility was amended to, among other things, provide for 2100 Energy’s acquisition of a portion of Deylau's limited liability company interest in our general partner in April 2015, increase certain of the collateral requirements, permit us to dispose of all of our limited liability company interest in MCE GP upon the satisfaction of various conditions, permit the Partnership to make cash distributions of up to $6.0 million per year to holders of our Series A Preferred Units and impose certain hedging requirements for our oil and natural gas assets upon our unwinding of any current hedges prior to the October 2015 redetermination date. 

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Preferred Units. On May 8, 2015, we completed a public offering of $44.0 million of our Series A Preferred Units at a price of $25.00 per unit. On June 5, 2015, the underwriters partially exercised the overallotment option and we issued an additional 170,000 Series A Preferred Units. Holders of our Series A Preferred Units are entitled to receive quarterly cash distributions at the rate of 11.0% per annum. The Series A Preferred Units are convertible into common units on any January 1, April 1, July 1 or October 1 by the holder at the initial conversion rate of 3.7821 common units per Series A Preferred Unit. We may elect to convert the Series A Preferred Units into our common units on or after July 15, 2018 in certain circumstances. We will redeem all of the Series A Preferred Units on July 15, 2022 at a redemption price equal to the liquidation preference of $25.00 plus an amount equal to accumulated but unpaid distributions thereon. If we do not redeem the Series A Preferred Units on July 15, 2022, then the per annum distribution rate will increase by an additional 2.0% per month until such redemption, up to a maximum rate per annum of 20.0%. See Note 9 "Cumulative Convertible Preferred Units" to our unaudited condensed consolidated financial statements in this report for further discussion of our Series A Preferred Units.

We received net proceeds, including proceeds from the exercise of the underwriters' option, of approximately $44.4 million from this offering after deducting underwriting discounts of $2.9 million and estimated offering costs of $1.0 million.  We used the net proceeds from the offering to repay a portion of the indebtedness outstanding under our credit facility.

Outlook

Beginning in the second half of 2014 and throughout 2015, the oil and natural gas market experienced a significant over supply of capacity, leading to a substantial and rapid decline in oil and natural gas prices, and subsequently, to significantly lower drilling and completion activity in the first half of 2015. As compared to the second quarter of 2014 and the first six months of 2014, the WTI index average prices for oil declined 44% and 47%, respectively. Natural gas and NGL pricing have also experienced similar declines. Additionally, there was a continuation of the decline in drilling activity in the second quarter of 2015.

Exploration and Production. As our revenue, earnings and cash flow are dependent on oil, natural gas and NGL prices, lower prevailing and future prices have resulted in lower revenue, earnings and cash flow in 2015. 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 continue to fluctuate significantly in the future. Lower prices have reduced and may continue to 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 and develop our reserves; 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 the first half of 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.

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 the second half of 2015, our ability to drill economic wells will be curtailed. Based on current commodity prices and continued increases in costs by our contract operator, we do not anticipate drilling any new wells in 2015.

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Although we monitored our costs and discussed expenses with our contract operator, we saw a significant rise in our lease operating expenses in 2014, which continued in the first half of 2015, compared to previous years and expect the higher costs to continue in the second half of 2015. In addition, we are currently engaged in litigation with our contract operator and its affiliates, which has significantly affected our exploration and production-related cash flow. See Note 14 "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, we reduced our 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 and June 30, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015 and $32.9 million during the second quarter of 2015. Continued low levels or further declines in oil, natural gas and NGL prices subsequent to June 30, 2015 are expected to result in additional ceiling test write downs in the third quarter of 2015 and in subsequent periods. The amount of any future impairment is difficult to predict, and will primarily depend on oil, natural gas and NGL prices during these periods.

Our credit facility is subject to a borrowing base which is generally set by the bank semi-annually on April 1 and October 1 of each year. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. In the second quarter of 2015, our borrowing base was lowered from $90.0 million to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. On May 29, 2015, the borrowing base was reduced further to $57.0 million in response to the settlement of a portion of our derivative contracts prior to their contractual maturity. As of June 30, 2015, the Partnership had $49.0 million of outstanding borrowings under the credit facility. We anticipate that our borrowing base will be further reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves.

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. Our customers' spending is based on a number of factors, including our customers’ forecasts of future energy demand, their expectations for future energy prices, their access to resources to develop and produce oil and natural gas, their ability to fund their capital programs and the impact of new government regulations. As a result of the rapid decline in oil prices, with both Brent and West Texas Intermediate prices dropping to near six-year lows in mid March of 2015 and 60% below 2014 peak highs, there has been a significant decrease in activity and customer spending. In North America, in response to lower oil prices, activity levels began to decline in late December 2014 and as of June 30, 2015, the U.S. rig count had fallen by approximately 930 rigs, or 51%, compared to the 2014 year-end rig count. During the second quarter of 2015, the North American rig count decline began to slow. For the remainder of the year, we expect unfavorable market conditions to continue and North American rig counts to remain relatively unchanged.

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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 the first half of 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 personnel and compensation and adjustments to planned capital expenditures. We began implementing certain cost reductions during the first quarter of 2015 with additional cost reductions becoming effective by the end of 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.

Corporate. We have taken steps to address potential shortfalls in cash flow from operations necessary to fund our investing and financing activities during the second quarter of 2015. In May 2015, we completed a public offering of our Series A Preferred Units. In June 2015, the underwriters partially exercised the overallotment option. We received net proceeds, including proceeds from the exercise of the underwriters' option, of approximately $44.4 million from this offering after deducting underwriting discounts of $2.9 million and estimated offering costs of $1.0 million.  We used the net proceeds from the offering to repay a portion of the indebtedness outstanding under our credit facility. 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.

Management is actively pursuing additional sources of capital. The Partnership, however, is dependent upon its ability to secure equity or debt financing or monetize certain of its oilfield services assets and there are no assurances that the Partnership will be successful in such endeavors. Possible sources of capital include some or all of the following:

•sell common units through our existing Equity Distribution Agreement;

•pursue additional financing for our oilfield services business;

•continue to suspend distributions on our common units for additional quarters; and

•divest assets.

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 common and preferred units for which we will pay distributions.

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The Partnership's ability to continue as a going concern depends on its ability to execute its business plan. However, our current cash position and our ability to access additional capital may limit our available opportunities and may not provide sufficient cash for operations, capital requirements or debt service. As we have violated debt covenants on certain of our oilfield service related debt, as discussed in Note 3 "Debt" to our unaudited condensed consolidated financial statements in this report, it is possible that we will have to pay amounts sooner than anticipated based on the original maturity. We anticipate that our borrowing base will be further reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management is actively pursuing additional sources of capital. We believe that we will be successful in securing any funds necessary to continue as a going concern. The Partnership, however, is dependent upon its ability to secure equity or debt financing or monetize certain of its oilfield services assets and there are no assurances that the Partnership will be successful in such endeavors.

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 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 and six months ended June 30, 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 11 "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."

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Set forth in the table below is financial, production and pricing information for our exploration and production segment for the three and six months ended June 30, 2015 and 2014.

	Three Months Ended June 30,					Six Months Ended June 30,
	2015			2014		2015			2014
Results (in thousands):
Oil sales	$	1,648		$	4,402	$	3,340		$	8,348
Natural gas sales	1,404			3,850		3,247			9,217
NGL sales	2,267			8,466		5,299			18,004
Total revenues	5,319			16,718		11,886			35,569
Production expenses	3,810			4,516		7,865			9,019
Production taxes	282			792		593			1,671
Total segment margin	1,227			11,410		3,428			24,879
Depreciation, depletion, amortization and accretion	3,620			6,970		8,413			12,857
Impairment	32,905			—		76,024			—
General and administrative	2,254			2,022		6,823			5,866
Operating (loss) income	$	(37,552	)	$	2,418	$	(87,832	)	$	6,156
Production volumes:
Oil (Bbls)	36,083			43,625		73,644			84,306
Natural gas (Mcf)	531,216			927,828		1,267,974			1,916,044
NGLs (Bbls)	172,722			241,695		362,411			447,278
Total production volumes (Boe)	297,341			439,958		647,384			850,925
Average daily production volumes (Boe)	3,267			4,835		3,577			4,701
Average price (excluding derivatives):
Oil (per Bbl)	$	45.67		$	100.91	$	45.35		$	99.02
Natural gas (per Mcf)	$	2.64		$	4.15	$	2.56		$	4.81
NGL (per Bbl)	$	13.13		$	35.03	$	14.62		$	40.25
Total (per Boe)	$	17.89		$	38.00	$	18.36		$	41.80
Average production costs (per Boe)(1)	$	12.81		$	10.26	$	12.15		$	10.60

__________

(1) Includes lease operating expense and workover expense.

Revenue

Revenues from our exploration and production segment were $5.3 million for the three months ended June 30, 2015, a decrease of $11.4 million, or 68.2%, compared to the three months ended June 30, 2014. Revenues were $11.9 million for the six months ended June 30, 2015, a decrease of $23.7 million, or 66.6%, compared to the same period in 2014. The decrease in revenues for both the three and six month period are primarily due to lower commodity prices and lower production. The average price per Boe received on our combined production decreased $20.11 and $23.44 in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014.

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Combined production decreased 142,617 Boe, or 32.4%, and 203,541 Boe, or 23.9%, in the three and six months ended June 30, 2015, respectively, from the same periods in 2014. These decreases are primarily due to our suspension of drilling activity and the expected natural production decline rate of our properties. The reduction in drilling activity due to unfavorable commodity prices and the performance of our contract operator has negatively impacted our ability to replace reserves and offset declining production. In the second quarter of 2015, as a result of increased seismic activity in Oklahoma, the Oklahoma Corporation Commission notified our contract operator that it would be required to reduce the amount of saltwater injected into certain of the saltwater disposal wells in the Southern Dome field, which resulted in further reductions in production. Additionally, an increased number of our wells required submersible pump and other repairs in the first six months of 2015, resulting in extended downtime for these wells in the Southern Dome field. 

Operating Expenses

Production expenses. Production expenses are costs associated with exploration and production activities, including lease operating expense and treating costs. As a non-operating working interest owner, we are subject to costs and fees as incurred and determined by the operator. See further discussion related to our contract operator in Note 11 "Related Party Transactions" and Note 14 "Commitments and Contingencies" to the Partnership’s unaudited condensed consolidated financial statements in Item 1. "Financial Statements" of this report.

Production expenses decreased $0.7 million, or 15.6%, and $1.2 million, or 12.8%, for the three and six months ended June 30, 2015, respectively, from the same periods in 2014. These decreases are primarily 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. Additionally, we incurred higher operator fees and costs on our production in 2015. As a result of these factors, production expenses increased $2.55 per Boe and $1.55 per Boe for the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014.

Production taxes. Production taxes decreased $0.5 million and $1.1 million, respectively, in the three and six months ended June 30, 2015, from the same periods in 2014. The decreases in production taxes are 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 $3.4 million and $4.4 million for the three and six months ended June 30, 2015, respectively, from the comparable periods in 2014. The lower depreciation, depletion and amortization is primarily attributable to reduced production levels, partially offset by an increased depletion rate caused by our reduced capital investment and declining reserves.

Impairment. Based on the 12-month average prices of oil, natural gas and NGLs as of June 30, 2015, we recorded an impairment of our oil and natural gas properties of $32.9 million during the second quarter of 2015. The impairment is a result of lower commodity prices and our suspension of drilling activity in late 2014 and continuing through 2015. Impairment of our oil and natural gas properties for the six months ended June 30, 2015 totaled $76.0 million. No impairment was considered necessary during the six months ended June 30, 2014.

General and administrative. General and administrative expense increased $0.2 million and $1.0 million for the three and six months ended June 30, 2015, respectively, from the comparable periods in 2014. The increase in general and administrative expense is primarily due to the issuance of equity awards in the first quarter of 2015. The six months ended June 30, 2015 includes $1.5 million of equity-based compensation related to awards that had accelerated vesting. Offsetting the increase are reductions to certain general and administrative expenses as part of cost cutting efforts the Partnership implemented in the second quarter of 2015.

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" to the Partnership's unaudited condensed consolidated financial statements for discussion of these acquisitions. The primary factors affecting the results of the oilfield services segment are the rates received and the volume of oilfield services provided.

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Set forth in the table below is financial information for our oilfield services segment for the three and six months ended June 30, 2015 and 2014.

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Results (in thousands):
Oilfield service revenue	$	18,765		$	10,100		$	50,315		$	18,676
Cost of providing oilfield services	14,637			5,968			37,696			10,534
Total segment margin	4,128			4,132			12,619			8,142
Depreciation and amortization	2,438			3,393			10,066			6,853
Impairment	66,784			—			66,784			—
General and administrative	4,417			1,467			12,082			3,184
Operating loss	$	(69,511	)	$	(728	)	$	(76,313	)	$	(1,895	)

Revenue

Oilfield services revenues are generally driven by changes in customer base and by drilling activity in the areas in which we operate. Revenues from our oilfield services segment were $18.8 million and $50.3 million for the three and six months ended June 30, 2015, respectively. The increase of $8.7 million and $31.6 million in the three and six month 2015 periods, respectively, over the same periods in 2014 are primarily due to expanded operations achieved through the June 2014 acquisition of 100% of the outstanding membership interests in EFS and RPS ("Services Acquisition"). Revenue from operations acquired in the Services Acquisition contributed $14.2 million and $38.3 million, respectively, during the three and six months ended June 30, 2015. Partially offsetting the revenue contributed by the Services Acquisitions was a decline in our existing blowout prevention services due to decreased drilling activity as a result of low commodity prices.

Operating Expenses

Cost of providing oilfield services. The cost of providing oilfield services for the three and six months ended June 30, 2015 was $14.6 million and $37.7 million, respectively. The increase is attributable to the Services Acquisition in June 2014. Costs of providing oilfield services associated with operations from the Services Acquisition were $8.7 million and $27.2 million for the three and six months ended June 30, 2015, respectively.

Depreciation and amortization. Depreciation and amortization expense was $2.4 million and $10.1 million for the three and six months ended June 30, 2015, respectively. The decrease of $1.0 million in the three month ended June 30, 2015 compared to the same period in 2014 is a result of no amortization being recorded on intangible assets in the second quarter of 2015. As discussed below, our intangible assets were fully impaired in 2015. The increase of $3.2 million in the six months ended June 30, 2015 compared to the same period in 2014 is primarily related to amortization recorded in the first quarter of 2015 on the intangible assets identified in the Services Acquisition as well as tangible assets in our oilfield services segment.

Impairment. In the second quarter of 2015, we performed our annual valuation of goodwill and an impairment analyses for our customer relationship and noncompete agreement intangible assets related to the June 2014 Services Acquisition.

As of April 1, 2015, the Partnership performed the annual impairment test on goodwill. Primarily as a result of a decrease in projected revenue of EFS, which is a significant component in determining the fair value of this reporting unit, the carrying value of the reporting unit exceeded its fair value. We performed step two of the impairment test to determine the amount of goodwill that was impaired. Based on this assessment, it was determined that goodwill was fully impaired and $9.3 million was recorded as impairment and included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015. There was no impairment recorded for the three or six months ended June 30, 2014.

In the second quarter of 2015, the Partnership deemed the continued significant decline in commodity prices and the related impact or estimated impact to our oilfield services business to be a triggering event for the purpose of evaluating its intangible assets for impairment. Accordingly, impairment tests were performed by calculating the estimated future cash flows to be generated by the respective revenue generating asset groups. The undiscounted future cash flows were less than the respective revenue generating asset groups' carrying value for the intangible assets from the Services Acquisition. Based on the discounted cash flows

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of the asset group, an impairment of these intangible assets, or approximately $51.2 million, was recorded and is included in the accompanying unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2015. There was no impairment recorded for the three or six months ended June 30, 2014.

Due to the continued depressed commodity environment and the impact on the demand for oilfield services, the Partnership analyzed its oilfield services equipment for impairment in the second quarter of 2015. Based on current utilization rates, the decline in rental rates and consideration of sales prices for similar oilfield services equipment, the Partnership recorded an impairment on its oilfield services equipment of approximately $6.3 million for the three and six months ended June 30, 2015.

General and administrative. General and administrative expense consists of non-field employee compensation, selling expenses, professional fees and occupancy costs. General and administrative expense was $4.4 million and $12.1 million for the three and six months ended June 30, 2015, respectively. The $3.0 million and $8.9 million respective increases over the same periods in 2014 reflect our expanded operations as a result of the Services Acquisition and includes equity compensation expense of $1.0 million and $3.6 million in the three and six months ended June 30, 2015, respectively.

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

Results of Operations

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

	Three Months Ended   June 30,						Six Months Ended   June 30,
	2015			2014			2015			2014
	(in thousands)
Operating (loss) income	$	(107,063	)	$	1,690		$	(164,145	)	$	4,261
Other income (expense):
Interest expense	(1,749		)	(1,015		)	(3,097		)	(1,984		)
(Loss) gain on derivative contracts, net	(1,067		)	(1,396		)	157			(4,528		)
Gain on investment in acquired business	—			2,298			—			2,298
Other income	23			9			57			7
Net (loss) income	$	(109,856	)	$	1,586		$	(167,028	)	$	54

Other Income/Expense

Interest expense. Interest expense increased $0.7 million and $1.1 million, respectively, for the three and six months ended June 30, 2015 compared to the same periods in 2014. The increase in 2015 was mainly due to the reduction in our borrowing base which resulted in the write-off of a proportionate amount of related debt issuance costs.

(Loss) gain on derivatives, net. The following table presents cash settlements on our derivative contracts as included in (loss) gain on derivative contracts, net in the accompanying unaudited statements of operations for the three and six months ended June 30, 2015 and 2014 (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Cash receipts (payments) upon settlement (1)	$	6,000	$	(983	)	$	8,339	$	(3,412	)

__________

(1) Cash receipts upon settlement of derivative contracts for the three and six months ended June 30, 2015 includes $3.9 million related to early settlements of certain derivative contracts. In the second quarter of 2015, we monetized certain of our derivative contracts for the periods October 2015 through December 2015 and calendar year 2016.

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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.

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A reconciliation of Adjusted EBITDA to net (loss) income for the three and six months ended June 30, 2015 and 2014 is provided below:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Reconciliation of adjusted EBITDA to net (loss) income:	(in thousands)
Net (loss) income	$	(109,856	)	$	1,586		$	(167,028	)	$	54
Interest expense	1,749			1,015			3,097			1,984
Depreciation, depletion and amortization	5,999			10,289			18,346			19,567
Accretion expense	59			74			133			143
Impairment	99,689			—			142,808			—
Non-cash compensation expense	461			386			4,322			644
Transaction fees	358			1,321			1,052			3,232
Gain on acquisition of a business	—			(2,298		)	—			(2,298		)
Loss (gain) on derivative contracts, net	1,067			1,396			(157		)	4,528
Cash received (paid) on settlement of derivative contracts	6,000			(983		)	8,339			(3,412		)
Other	433			—			1,152			—
Change in fair value of contingent consideration	—			(1,345		)	—			(912		)
Adjusted EBITDA	$	5,959		$	11,441		$	12,064		$	23,530

A reconciliation of Adjusted EBITDA to net loss for our exploration and production and oilfield services segments for the three and six months ended June 30, 2015 is provided below:

	Three Months Ended						Six Months Ended
	June 30, 2015						June 30, 2015
	E&P			OFS			E&P			OFS
Reconciliation of adjusted EBITDA to net loss:	(in thousands)
Net loss	$	(39,855	)	$	(70,001	)	$	(89,777	)	$	(77,251	)
Interest expense	1,234			515			2,101			996
Depreciation, depletion and amortization	3,561			2,438			8,280			10,066
Accretion expense	59			—			133			—
Impairment	32,905			66,784			76,024			66,784
Non-cash compensation expense	(511		)	972			715			3,607
Transaction fees	358			—			1,052			—
Loss (gain) on derivative contracts, net	1,067			—			(157		)	—
Cash received on settlement of derivative contracts	6,000			—			8,339			—
Other	255			178			632			520
Adjusted EBITDA	$	5,073		$	886		$	7,342		$	4,722

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.

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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.

We will need to raise additional cash to fund our operations and implement our business plan. Future contingencies, developments and unknown events could cause us to require more working capital during the 12-month period ending June 30, 2016. We anticipate that we may incur operating losses in the next twelve months. We have historically financed our operations through equity issuances and debt financings. Management is actively pursuing additional sources of capital. However, we do not currently have any arrangements for financing and we can provide no assurance to investors that we will be able to find such financing if required.

Because we have limited resources, we may not be able to compete in the capital markets with much larger, established companies that have ready access to capital. Our ability to obtain needed financing may be impaired by conditions and instability in the capital markets (both generally and in the oil and natural gas industry in particular), prices of oil and natural gas on the commodities markets (which will impact the amount of financing available to us), and other factors. These factors may make the timing, amount, terms or conditions of additional financing unavailable to us. There is no assurance that we can raise the capital necessary to fund our business plan. Failure to raise the required capital to fund operations, on favorable terms or at all, will have a material adverse effect on our operations.

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 growth capital expenditures will be discretionary. As discussed in the Outlook section above, we have reduced our 2015 capital expenditures for exploration and production activities with minimal maintenance activities planned for existing wells and no currently planned drilling activity.

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.

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Distributions are declared and distributed within 45 days following the end of each quarter. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the six months ended June 30, 2015 and 2014, are shown in the following table (in thousands, except per unit amounts):

Distributions	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
Second Quarter	N/A	$	—	$	—	$	—	$	—	$	—
2014
First Quarter	May 15, 2014	$	0.580	$	7,852	$	1,279	$	90	$	9,221
Second Quarter	August 15, 2014	$	0.585	$	9,025	$	1,290	$	91	$	10,406

On June 18, 2015, the Partnership declared a quarterly distribution on our Series A Preferred Units of $0.5118 per unit, prorated for the period May 9, 2015 to July 14, 2015, to holders of record on July 1, 2015.

On July 29, 2015, the Partnership announced the suspension of the quarterly cash distributions on our common units.

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 $16.6 million and $14.7 million for the six months ended June 30, 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 the 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 $6.3 million and $84.7 million for the six months ended June 30, 2015 and 2014, respectively. Net cash used in investing activities was higher in 2014 than 2015, primarily due to the CEU Acquisition and the Services Acquisition. Additions to oil and natural gas properties were also higher in 2014 than 2015, as we decided in late 2014 to suspend drilling activity until commodity prices are more favorable. These items are partially offset by capital expenditures for our oilfield services segment as a result of expanded operations. Capital expenditures for the six months ended June 30, 2015 were primarily related to new facilities for our oilfield services segment.

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 $(10.0) million and $71.0 million for the six months ended June 30, 2015 and 2014, respectively. Net cash used in financing activities for the six months ended June 30, 2015 reflects total proceeds of $44.5 million, net of discounts and fees, received from the issuance of our Series A Preferred Units in the second quarter of 2015. Additionally, the 2015 period reflects the payment of $41.0 million on amounts outstanding under the credit facility. Net cash provided by financing activities for the six months ended June 30, 2014 includes net proceeds of approximately $76.2 million from the equity offering in April 2014.

Working Capital

Working capital is the difference in current assets and current liabilities and is an indicator of liquidity and the potential need for short-term funding. The changes in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, debt repayments and contingent consideration.

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Our working (deficit) capital was $(27.2) million and $3.4 million at June 30, 2015 and December 31, 2014, respectively. The working deficit is attributable, in part, to reduced operating cash flow and lower accounts receivable related to the reduction in sales in both segments during the six months ended June 30, 2015. Also contributing to the working deficit at June 30, 2015 compared to the working capital at December 31, 2014 is the increase in the current portion of debt, primarily as a result of not complying with debt covenants on certain of our debt.

The former owners of EFS and RPS are entitled to receive additional consideration in the form of common units 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 June 30, 2015 and December 31, 2014 would have been $(5.3) million and $15.0 million, respectively. As a result of ongoing discussions with the former owners, we have not yet issued common units to satisfy the equity portion of the contingent consideration obligation. Refer to "Outlook" above for a discussion of our 2015 outlook, including discussion of liquidity and capital resources.

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 six months ended June 30, 2015 and 2014, our maintenance capital expenditures were approximately $1.2 million and $7.6 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.

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.

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In the second quarter of 2015, the credit facility was amended to, among other things, provide for 2100 Energy’s acquisition of a portion of Deylau's limited liability company interest in our general partner in April 2015, increase certain of the collateral requirements, permit us to dispose all of our limited liability company interest in MCE GP upon the satisfaction of various conditions as described in Note 11 "Related Party Transactions," permit the Partnership to make cash distributions of up to $6.0 million per year to holders of our Series A Preferred Units and impose certain hedging requirements for our oil and natural gas assets upon our unwinding of any current hedges prior to the October 2015 redetermination date.

Additionally, the credit facility contains various covenants and restrictive provisions that, among other things, limit the ability of the Partnership to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. The credit facility permits the Partnership to make distributions to its common unit holders in an amount not to exceed "available cash" (as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership) if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed 90%. As of June 30, 2015, the Partnership was in compliance with all covenants under the credit facility.

Our credit facility is subject to a borrowing base which is generally set by the bank semi-annually on April 1 and October 1 of each year. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. In the second quarter of 2015, our borrowing base was lowered from $90.0 million to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. On May 29, 2015, the borrowing base was reduced further to $57.0 million in response to the settlement of a portion of our derivative contracts prior to their contractual maturity. We anticipate that our borrowing base will be further reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. As of June 30, 2015, the Partnership had $49.0 million outstanding borrowings with $8.0 million of available borrowing capacity.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At June 30, 2015 and December 31, 2014, the average annual interest rate on borrowings outstanding under the credit facility was 3.19% and 3.44%, respectively.

Notes Payable

MCES Notes Payable. The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. The notes range from 12 to 60 months in duration with maturity dates from August 2015 through March 2019 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. Certain of these notes contain a requirement for MCES to maintain a fixed charge ratio of not less than 1.25 to 1.0. As of June 30, 2015, MCES was not in compliance with the covenants under certain of these notes. As a result, the outstanding balances for these notes were reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015. The Partnership had $5.5 million outstanding, of which $4.9 million was current, under the MCES notes payable as of June 30, 2015.

EFS Loan Agreement. In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on EFS' existing notes payable, which were originally set to mature on June 26, 2015. In March 2015, we refinanced EFS' notes payable to extend the maturity date to March 2018. The balance on the note payable at June 30, 2015 was $10.8 million.

The note payable has a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at June 30, 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.

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

MCES Promissory Notes. On January 9, 2015 and February 24, 2015, MCES issued promissory notes totaling approximately $1.4 million, to acquire land from entities owned 50% by Mr. Kos and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner. Both promissory notes bear interest at prime plus one percent and are payable, including all accrued interest, on December 31, 2015. No payments are due prior to maturity. See Note 11 "Related Party Transactions" for additional discussion of the related party land transactions.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. In June 2015, the line of credit was lowered to a maximum of $3.0 million with the borrowing base determined based on MCES' eligible accounts receivable. Our monthly interest only payments accrue at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at June 30, 2015. The line of credit matures in September 2015 and is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. The outstanding balance was $2.4 million at June 30, 2015 and was reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at June 30, 2015.

The line of credit contains a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of June 30, 2015, MCES was not in compliance with this covenant under the line of credit.

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 $5.1 million as of June 30, 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 six months ended June 30, 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.

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.

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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 June 30, 2015, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:

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

The following tables present our derivative instruments outstanding as of June 30, 2015:

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
July 2015 - September 2015	9,317	$	80.00	$	93.25
October 2015 - December 2015	26,220	$	55.00	$	67.00
January 2016 - March 2016	25,935	$	55.00	$	67.00
April 2016 - December 2016	45,375	$	55.00	$	69.20

Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
July 2015 - December 2015	9,200	$	77.50	$	92.50	$	102.60

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Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
July 2015 - September 2015	10,777	$	88.90

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
July 2015 - September 2015	325,114	$	4.00	$	4.32
October 2015 - December 2015	340,400	$	2.85	$	3.46
January 2016 - March 2016	336,700	$	2.85	$	3.46
April 2016 - December 2016	1,017,500	$	2.85	$	3.40

Natural gas put options	Volumes (MMBtu)	Floor Price
July 2015 - December 2015	210,876	$	3.50

Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
July 2015 - September 2015	194,461	$	4.25

NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
July 2015 - September 2015	20,782	$	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 cash settlements on our derivative contracts as included in (loss) gain on derivative contracts, net in the accompanying unaudited statements of operations for the three and six months ended June 30, 2015 and 2014 (in thousands):

	Three Months Ended June 30,					Six Months Ended June 30,
	2015		2014			2015		2014
Cash receipts (payments) upon settlement (1)	$	6,000	$	(983	)	$	8,339	$	(3,412	)

__________

(1) Cash receipts upon settlement of derivative contracts for the three and six months ended June 30, 2015 includes $3.9 million related to early settlements. In the second quarter of 2015, we monetized certain of our derivative contracts for the periods October 2015 through December 2015 and calendar year 2016.

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.

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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 June 30, 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 June 30, 2015, we had debt outstanding under our credit facility of $49.0 million. A 1% increase in LIBOR on our outstanding debt under our credit facility as of June 30, 2015 would result in an estimated $0.5 million increase in annual interest expense.

ITEM 4.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of our principal executive officer and principal 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 June 30, 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 principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of June 30, 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.

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.

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As of June 30, 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 weakness.

Changes in Internal Control over Financial Reporting

There was no change in the Company’s internal control over financial reporting during the quarter ended June 30, 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.

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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, including the matters described in "Note 15–Commitments and Contingencies" to our consolidated financial statements in Item 8 “Financial Statements and Supplementary Data" of our 2014 Form 10-K and in Item 1 of Part II, “Legal Proceedings,” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015, as supplemented by the following. 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, Mr. 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 certain of the motions to dismiss was held on August 5, 2015 with another hearing scheduled for September 11, 2015. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action.

In addition to the proceeding described above, on January 29, 2015, the Partnership received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by the Partnership to NSEC. The total amount of the purported claims totaled approximately $1.9 million. During 2015, New Dominion has withheld all revenue from the Partnership's sold oil and natural gas production in satisfaction of these claims and other amounts New Dominion and its affiliates claim to be owed by the Partnership. The Partnership disputes New Dominion’s claims and related withholding of revenue, and on June 4, 2015, the Partnership amended a previously filed lawsuit against New Dominion pending in the District Court of Tulsa County, Oklahoma to add certain of New Dominion’s officers as well as David Chernicky as defendants. In the lawsuit, the Partnership seeks a temporary and permanent injunction and declaratory action and asserts breach of contract, negligence, gross negligence, willful misconduct and fraud against the various defendants. No hearing date has been set in this matter.

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

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

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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.

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.

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 each of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2015 and our 2014 Form 10-K, which are incorporated by reference in this report.

We may have difficulty meeting our capital expenditure obligations and financial commitments, which could adversely affect our business, financial condition and our ability to pay distributions on our units, including our common units and Series A Preferred Units.

We have experienced, and expect to continue to experience, capital expenditure and working capital requirements. We make and expect to continue to make capital expenditures in our business for the development and maintenance of our oilfield services business. We intend to finance our future capital expenditures and working capital requirements with cash flow from operations, borrowings under our revolving credit facility and proceeds from debt and/or equity offerings. However, our credit facility contains restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders. We also face financial commitments and contingencies that may limit our liquidity, impose restrictions on our capital expenditures and adversely affect our working capital.

Our ability to borrow under our credit facility is subject to limitations based on its terms and certain financial covenants. As of June 30, 2015, our 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. Our obligations under the credit facility are secured by substantially all of our oil and natural gas properties and other assets, excluding assets of our subsidiaries. Our credit facility matures in February 2017.

Additionally, our 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. These restrictions could adversely affect our ability to meet our working capital requirements. In addition, the credit facility permits us to make distributions to our 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%. In the second quarter of 2015, our borrowing base was lowered from $90.0 million to $60.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions. On May 29, 2015, the borrowing base was reduced further to $57.0 million in response to the settlement of a portion of our derivative contracts prior to their contractual maturity. We anticipate that our borrowing base will be further reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. As of June 30, 2015, we had $49.0 million in outstanding borrowings under the credit facility.

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Our liquidity has been limited by the withholding of our revenue by New Dominion, our contract operator. We have entered into agreements with New Dominion, under which we rely on it to operate all of our existing producing wells and coordinate our development drilling program.  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 and in the first half of 2015. In addition, we are currently engaged in litigation with New Dominion and its affiliates. On January 29, 2015, we received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by us to NSEC. The purported claims totaled approximately $1.9 million. During 2015, New Dominion has withheld all revenue from our sold oil and natural gas production in satisfaction of these claims and other amounts New Dominion and its affiliates claim to be owed by us. We dispute New Dominion’s claims and related withholding of revenue, and on June 4, 2015, we amended a previously filed lawsuit against New Dominion pending in the District Court of Tulsa County, Oklahoma to add certain of New Dominion’s officers as well as David Chernicky as defendants. The withholding of revenues by New Dominion has had and will continue to have a material adverse effect on our business, results of operations and financial condition and an adverse effect on our liquidity and ability to pay distributions to our unitholders.

The restrictions on our ability to obtain financing and the contingencies that limit our liquidity raise doubt about our ability to continue as a going concern. Our future is dependent upon our ability to obtain financing and upon future profitable operations from the development of our business. We have incurred net losses of $109.9 million and $167.0 million for the three and six months ended June 30, 2015, respectively. If we are unable to raise sufficient capital to fund our capital expenditures and working capital requirements, we may be forced to continue to curtail our drilling, development and other activities, which could result in a further decrease in our oil, natural gas and NGL production. We may also have difficulty funding the costs of providing our oilfield services. Our inability to sustain our operations may cause us to continue to accrue net losses and raise substantial doubt on our ability to continue as a going concern, which will further impair our ability to obtain additional debt or equity financing necessary to conduct our operations. See Note 1 “Basis of Presentation - Liquidity" to our unaudited condensed consolidated financial statements in this report for additional discussion.

Although we may generate sufficient net cash provided by operating activities during any particular quarter, the board of directors of our general partner has the ability under our limited partnership agreement to establish a cash reserve, which could encompass all of the cash otherwise available for distribution, to provide for the proper conduct of our business in both the short and long term. To provide for the proper conduct of our business, the board of directors of our general partner can determine to reserve cash to reduce indebtedness, among other things.

Any decision to reserve some or all of our cash on hand for such purposes and not distribute it may significantly impact our unitholders, as well as our business and operations. The market value of our common units and Series A Preferred Units may decrease in response to or in anticipation of a decrease or suspension of a distribution. Suspension of a distribution may have a tax impact on our unitholders. Please see the risk factor in our 2014 Form 10-K entitled “You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us” for more information. On July 29, 2015, we suspended the quarterly cash distributions on our common units. We may continue to suspend distributions on our common units for additional quarters and may suspend distributions on our Series A Preferred Units in future periods. External perceptions of the health of our business and our liquidity may also be impacted, which could further limit our ability to access capital markets, cause our vendors to tighten our credit terms and cause a strain in our relationship with other business partners. Further, our employees may become distracted from our day to day operations due to concern about our business and unit price.

If our liquidity position does not improve and our capital expenditures continue to be limited or are further reduced in the future, our business, financial condition and our ability to pay distributions on our units, including our common units and Series A Preferred Units, could be further adversely affected.

The tax treatment of publicly-traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present United States federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for United States federal income tax purposes.

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In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to the United States federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for United States federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

Legislation or regulatory initiatives intended to address seismic activity could restrict our ability to dispose of saltwater gathered from our customers and, accordingly, could have a material adverse effect on our business.

New Dominion disposes of large volumes of saltwater that we generate in connection with our drilling and production operations, pursuant to permits issued to New Dominion by governmental authorities overseeing such disposal activities, including, for example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division, or OGCD, in Oklahoma where New Dominion conducts operations on our behalf. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.

For example, there exists a growing concern that the injection of saltwater into belowground disposal wells triggers seismic activity in certain areas, including Oklahoma. In response to these concerns, the Oklahoma Corporation Commission adopted rules in 2014 for operators of saltwater disposal wells in certain seismically-active areas, or Areas of Interest, in the Arbuckle formation, requiring operators to monitor and record well pressure and discharge volume on a daily basis and further requiring operators of wells permitted for disposal of 20,000 barrels per day or more of saltwater to conduct mechanical integrity testing. On March 25, 2015, the OGCD issued a directive, expanding the Areas of Interest for induced seismicity. Under the new directive, operators of 347 disposal wells located within the expanded Areas of Interest of the Arbuckle formation were given until April 18, 2015 to demonstrate that their wells were not disposing into or in communication with the crystalline basement rock. Operators of wells in contact or communication with the basement rock were required to reduce the depth of, or “plug back,” those wells or, alternatively, to reduce disposal volume by 50%. On July 17, 2015, the OGCD issued another directive, further expanding the covered area to include an additional 211 disposal wells. Under this second directive, operators were given until August 14, 2015 to prove that they were not injecting below the Arbuckle formation or, as necessary, to plug back those wells in contact or communication with the crystalline basement rock, without the option of reducing disposal volume by 50%. Most recently, on August 3, 2015, the OGCD has imposed further reductions on oil and natural gas wastewater disposal well volume in a prescribed area of northern Oklahoma County and southern Logan County, requiring operators to reduce disposal volumes for affected wells by approximately 38% below 2014 reported volumes, within a specified 30-day period. As a result of these directives, New Dominion has been ordered by the OGCD with respect to three of its wells in the Southern Dome field to plug back the depth of these disposal wells or limit the volume of salt water disposed on a daily basis. New Dominion has taken steps to reduce volumes of salt water being injected in the affected disposal wells, resulting in reduced current levels of our production that are currently utilizing those affected disposal wells, which will continue if other economically feasible options to dispose of the salt water are not pursued.

The adoption and implementation of any new laws, regulations, or directives that restrict our ability to dispose of saltwater gathered from production pursued by New Dominion on our behalf, whether by plugging back the depths of disposal wells, reducing the volume of oil and natural gas wastewater disposed in such wells, restricting disposal well locations or otherwise, or by requiring New Dominion to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

ITEM 6. Exhibits

See the Exhibit Index accompanying this Quarterly Report.

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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 August 11, 2015.

New Source Energy Partners L.P.
By: New Source Energy GP, LLC, its general partner
/s/ Amber N. Bonney
By:	Amber N. Bonney
Title:	Vice President Accounting and Principal Accounting Officer
	(Duly Authorized Signatory and Chief Accounting Officer)

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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	Second Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.	8-K	001-35809	3.1	5/14/2015
3.3	Certificate of Formation of New Source Energy GP, LLC	S-1	333-185754	3.4	1/11/2013
3.4	Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC	8-K	001-35809	3.2	2/15/2013
3.5	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
3.6	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	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
10.2	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
10.3	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
10.4	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
10.5	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 Kristian B. Kos, principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					*
31.2	Certification of Amber N. Bonney, principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.					*
32.1	Certifications of Kristian B. Kos, Chief Executive Officer, and Amber N. Bonney, principal 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					*

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101.DEF(a)	XBRL Definition Linkbase Document	*
101.LAB(a)	XBRL Labels Linkbase Document	*
101.PRE(a)	XBRL Presentation Linkbase Document	*

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