New Source Energy Partners (NSLP) 10-Q 2015 Q3 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 September 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 November 2, 2015, the registrant had 16,522,775 common units and 2,205,000 subordinated units outstanding.

NEW SOURCE ENERGY PARTNERS L.P.

Form 10-Q

Quarter Ended September 30, 2015

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)
		Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	5
		Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2015 and 2014	7
		Condensed Consolidated Statement of Unitholders' Equity (Deficit) for the nine months ended September 30, 2015	8
		Condensed Consolidated Statements of Cash Flows for the nine months ended September 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	39
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58
	Item 4.	Controls and Procedures	60
PART II – OTHER INFORMATION
	Item 1.	Legal Proceedings	62
	Item 1A.	Risk Factors	65
	Item 3.	Defaults Upon Senior Securities	68
	Item 6.	Exhibits	69

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;

• "NGL" refers to natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams;

• "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 Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 2015.

4

PART I: Financial Information

ITEM 1. Financial Statements

New Source Energy Partners L.P. Condensed Consolidated Balance Sheets (Unaudited)
	September 30, 2015			December 31, 2014
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash	$	1,418		$	5,504
Restricted cash	457			350
Accounts receivable, net	11,477			31,919
Accounts receivable-related parties, net	5,480			4,946
Derivative contracts	1,075			8,248
Inventory	3,557			4,236
Prepaid expenses	3,965			2,011
Other current assets	730			478
Total current assets	28,159			57,692
Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	333,186			332,413
Less: Accumulated depreciation, depletion, amortization, and impairment	(289,948		)	(153,734		)
Total oil and natural gas properties, net	43,238			178,679
Property and equipment, net	66,985			68,886
Intangible assets, net	—			56,377
Goodwill	—			9,315
Derivative contracts	161			1,818
Other assets	1,116			2,779
Total assets	$	139,659		$	375,546

5

New Source Energy Partners L.P. Condensed Consolidated Balance Sheets - continued (Unaudited)
	September 30, 2015			December 31, 2014
	(in thousands, except unit amounts)
LIABILITIES, REDEEMABLE PREFERRED UNITS AND UNITHOLDERS' EQUITY (DEFICIT)
Current liabilities:
Accounts payable and accrued liabilities	$	15,556		$	15,326
Accounts payable-related parties	2,651			2,318
Factoring payable	3,653			13,152
Contingent consideration payable	12,913			11,572
Current portion of long-term debt	74,340			11,825
Other current liabilities	2,319			113
Total current liabilities	111,432			54,306
Long-term debt	413			95,218
Contingent consideration payable	—			10,801
Asset retirement obligations	3,765			3,568
Other liabilities	—			339
Total liabilities	115,610			164,232
Commitments and contingencies (Note 14)
Series A Cumulative Convertible Redeemable Preferred Units (1,930,000 units issued and outstanding at September 30, 2015 and none issued and outstanding at December 31, 2014)	44,982			—
Unitholders' equity (deficit):
Common units (16,522,775 units issued and outstanding at September 30, 2015 and 16,160,381 units issued and outstanding at December 31, 2014)	20,188			231,510
Common units held in escrow	(2,131		)	(6,955		)
Subordinated units (2,205,000 units issued and outstanding at September 30, 2015 and December 31, 2014)	(56,410		)	(28,717		)
General partner's units (none issued and outstanding at September 30, 2015 and 155,102 units issued and outstanding at December 31, 2014)	—			(1,944		)
Total New Source Energy Partners L.P. unitholders' (deficit) equity	(38,353		)	193,894
Noncontrolling interest	17,420			17,420
Total unitholders' (deficit) equity	(20,933		)	211,314
Total liabilities, redeemable preferred units and unitholders' equity (deficit)	$	139,659		$	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 September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(in thousands, except per unit amounts)
Revenues:
Oil sales	$	566		$	3,798		$	3,906		$	12,146
Natural gas sales	1,175			3,711			4,422			12,928
NGL sales	2,083			8,052			7,382			26,056
Oilfield services	16,281			40,863			66,596			59,539
Total revenues	20,105			56,424			82,306			110,669
Operating costs and expenses:
Oil, natural gas and NGL production	3,976			4,894			11,841			13,913
Production taxes	197			668			790			2,339
Cost of providing oilfield services	13,777			24,315			51,473			34,849
Depreciation, depletion and amortization	5,329			17,760			23,675			37,329
Accretion	70			77			203			219
Impairment	49,141			—			191,949			—
General and administrative	8,569			13,785			27,474			22,835
Total operating costs and expenses	81,059			61,499			307,405			111,484
Operating loss	(60,954		)	(5,075		)	(225,099		)	(815		)
Other income (expense):
Interest expense	(832		)	(1,458		)	(3,929		)	(3,442		)
Gain (loss) on derivative contracts, net	1,794			3,768			1,951			(760		)
Gain on investment in acquired business	—			—			—			2,298
Other (expense) income	(1,536		)	11			(1,479		)	18
Net loss	(61,528		)	(2,754		)	(228,556		)	(2,701		)
Less: net income attributable to noncontrolling interest	—			242			—			242
Net loss attributable to New Source Energy Partners L.P.	(61,528		)	(2,996		)	(228,556		)	(2,943		)
distributions on Series A Preferred Units	1,327			—			2,315			—
accretion of discount on Series A Preferred Units	281			—			457			—
Net loss attributable to New Source Energy Partners L.P. common, subordinated and general partner units	$	(63,136	)	$	(2,996	)	$	(231,328	)	$	(2,943	)
Net loss per unit:
Net loss per general partner unit	$	—		$	(0.17	)	$	(3.03	)	$	(0.19	)
Net loss per subordinated unit	$	(3.38	)	$	(0.17	)	$	(12.74	)	$	(0.19	)
Net loss per common unit	$	(3.38	)	$	(0.17	)	$	(12.34	)	$	(0.20	)

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 (Deficit)

For the Nine Months Ended September 30, 2015

(Unaudited)

	Common				Subordinated				General Partner					Non-controlling Interest		Total Unitholders' Equity (Deficit)
	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	207,292	5,251			—	—			—		—			—		5,251
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	—	(2,041		)	—	(274		)	—		—			—		(2,315		)
Accretion of discount on Series A Preferred Units	—	(403		)	—	(54		)	—		—			—		(457		)
Escrow units issued	—	668			—	—			—		—			—		668
Net loss	—	(200,721		)	—	(27,365		)	—		(470		)	—		(228,556		)
Balance, September 30, 2015	16,522,775	$	18,057		2,205,000	$	(56,410	)	—		$	—		$	17,420	$	(20,933	)

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)
	Nine Months Ended September 30,
	2015			2014
	(in thousands)
Cash Flows from Operating Activities:
Net loss	$	(228,556	)	$	(2,701	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	23,675			37,329
Impairment	191,949			—
Accretion	203			219
Amortization of deferred loan costs	740			451
Bad debt expense	1,475			—
Write-off of deferred loan costs	332			—
Write-off of deferred offering costs	1,005			—
Equity-based compensation	5,251			1,906
Escrow units issued	668			—
Change in fair value of contingent consideration	—			4,493
Gain on investment in acquired business	—			(2,298		)
(Gain) loss on derivative contracts, net	(1,951		)	760
Cash received (paid) on settlement of derivative contracts	10,781			(3,750		)
Changes in operating assets and liabilities:
Accounts receivable	18,433			(4,533		)
Inventory	(2,786		)	(3,786		)
Other current assets and other assets	(519		)	204
Accounts payable and accrued liabilities	(3,086		)	(1,893		)
Other current liabilities and other liabilities	1,500			—
Net cash provided by operating activities	19,114			26,401
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	—			(63,446		)
Additions to oil and natural gas properties	(1,112		)	(20,845		)
Additions to other property and equipment	(6,288		)	(6,726		)
Net cash used in investing activities	(7,400		)	(91,017		)
Cash Flows from Financing Activities:
Proceeds from issuance of Series A Preferred Units, net	44,525			—
Proceeds from borrowings	9,165			22,544
Payments on borrowings	(52,012		)	(8,401		)
Deposit for financing insurance	(380		)	—
Bank overdraft	—			281
Proceeds from financing	—			527
Proceeds from borrowings, net - related party	—			300
Payments for deferred loan costs	—			(437		)
Payments on factoring payable, net	(9,499		)	(2,221		)
Proceeds from sales of common units, net of offering costs	—			76,191
Payments of offering costs	—			(100		)
Distribution to unitholders	(7,599		)	(25,663		)

9

New Source Energy Partners L.P.  Condensed Consolidated Statements of Cash Flows - continued (Unaudited)
Net cash (used in) provided by financing activities	(15,800		)	63,021
Net change in cash and cash equivalents	(4,086		)	(1,595		)
Cash and cash equivalents, beginning of period	5,504			7,291
Cash and cash equivalents, end of period	$	1,418		$	5,696
Supplemental Cash Flow Information:
Cash paid for interest	$	3,031		$	2,999
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation	$	—		$	203
Decrease in accrued capital expenditures	$	917		$	(1,561	)
Common units issued in connection with acquisitions	$	—		$	(46,239	)
Factoring payable assumed in connection with acquisitions	$	—		$	15,840
Acquisition of property and equipment by financing	$	1,200		$	6,707
Distributions payable to noncontrolling interest	$	—		$	242
Distributions payable on Series A Preferred Units	$	1,327		$	—
Accretion of discount on Series A Preferred Units	$	457		$	—
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 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 September 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. The borrowing base on our senior secured revolving credit facility (the "credit facility") was reduced at the October 2015 redetermination due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. Our credit facility requires any deficiency to be settled in full within 30 days or in equal installments over a 90-day period. During a deficiency, an additional 2% is applied to the interest rate on the outstanding balance under the credit facility, not to exceed the maximum rate as defined in the credit agreement. Our lenders also have the option to cause the liquidation of collateral in order to satisfy the deficiency.

11

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

The Partnership does not currently have sufficient cash resources to repay or additional collateral to cure the borrowing base deficiency of $25.0 million. If the Partnership is unable to successfully negotiate a forbearance agreement, obtain a waiver of compliance or cure the borrowing base deficiency, an event of default under the Credit Facility would occur on November 9, 2015. The Partnership is in discussions with the lenders under the credit facility and expects to enter into a forbearance arrangement soon. In an event of default, the administrative agent may, and at the request of the majority of lenders, declare the outstanding balance under the credit facility immediately due and payable. Additionally, we have violated debt covenants on our credit facility and certain of our oilfield service related debt as discussed in Note 3 "Debt." While our lenders have not called the debt, it is possible that we will have to pay amounts outstanding sooner than anticipated based on the original maturity. These factors raise substantial doubt about the Partnership’s ability to continue as a going concern.

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. If we are unsuccessful in securing additional financing, we expect that we will not be able to meet our obligations as they come due. 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 August 2015, the FASB released ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date" ("ASU 2015-14"). ASU 2015-14 delays the effective date of ASU 2014-09 by one year, making it effective for fiscal years, and interim periods within those years, beginning after December 15, 2017, with early adoption permitted as of the original effective date. 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 this 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" ("ASU 2015-03"), 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.

12

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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)” ("ASU 2015-06"), 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 standard will have.

In August 2015, the FASB issued ASU No. 2015-15, “Interest-Imputation of Interest” ("ASU 2015-15") which permits entities to defer and present debt issuance costs related to line-of-credit arrangements as assets, consistent with ASU No. 2015-03. ASU 2015-15 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted. We do not expect the adoption of this guidance to have a material effect on our consolidated financial statements.

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").

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

__________

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

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

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

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

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

__________

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

(2) The 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 of the MCCS Contingent Consideration.

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

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

__________

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

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

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

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

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

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

__________

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

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

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

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

__________

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

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

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

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

__________

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

The amount of revenues and operating income included in the accompanying unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2014 generated by the 2014 Material Acquisitions are shown in the table below. The operating income attributable to the CEU Acquisition represents the excess of 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   September 30, 2014		Nine Months Ended September 30, 2014
	(in thousands)
Revenue	$	30,110	$	35,047
Excess of revenue over direct operating expenses	$	590	$	2,786

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

3.  Debt

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

	September 30, 2015		December 31, 2014
Credit facility	$	49,000	$	83,000
Notes payable	14,449		20,424
Notes payable–related parties	10,549		—
Line of credit	755		3,619
Total debt	74,753		107,043
Less: current maturities	74,340		11,825
Long-term debt	$	413	$	95,218

Senior Secured Revolving Credit Facility

The Partnership has a credit facility that, as of September 30, 2015, 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.

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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 certain conditions, 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. See Note 11 "Related Party Transactions" for additional discussion of 2100 Energy's acquisition of interest in our general partner.

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 September 30, 2015, the Partnership was not in compliance with certain covenants under the credit facility. As a result, the outstanding balance under the credit facility was reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at September 30, 2015.

Our credit facility is subject to a borrowing base that 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 $57.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions and with consideration of the settlement of a portion of our derivative contracts prior to their contractual maturity. As of September 30, 2015, the Partnership had $49.0 million in outstanding borrowings with no available borrowing capacity. As a result of our semi-annual redetermination on October 9, 2015, our borrowing base was reduced to $24.0 million due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. The reduced borrowing base results in a borrowing deficiency of $25.0 million. Any deficiency under the credit facility is required to be settled in full within 30 days or in equal installments over a 90-day period. During a deficiency, an additional 2.00% is applied to the interest rate on the outstanding balance under the credit facility, not to exceed the maximum rate as defined in the credit agreement. Our lenders also have the option to cause the liquidation of collateral in order to satisfy the deficiency. In an event of default, the administrative agent may, and at the request of the majority of lenders, declare the outstanding balance under the credit facility immediately due and payable. The Partnership is in discussions with the lenders under the credit facility and expects to enter into a forbearance arrangement soon.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.50%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At September 30, 2015 and December 31, 2014, the average annual interest rate on borrowings outstanding under the credit facility was 3.47% and 3.44%, respectively. The forbearance agreement or any waiver may postpone interest payments for a certain time frame. However, interest may continue to accrue at the default rate.

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 September 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 September 30, 2015. The Partnership had $4.6 million outstanding, of which $4.2 million was current, under the MCES notes payable as of September 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, the EFS notes were refinanced with the maturity date extended to March 2018. The balance on the note payable at September 30, 2015 was $9.9 million.

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

The note payable has a variable interest rate based on the Bank 7 Base Rate minus 2.30% with a minimum and initial interest rate of 5.50%. The effective rate was 5.50% at September 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 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 and increasing to at least $3.5 million by October 1, 2015, in each case as more fully described in the loan agreement. As of September 30, 2015, EFS and RPS were in default for failing to comply 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 September 30, 2015.

Notes Payable—Related Parties

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 wholly-owned by Messrs. Kos and 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. Effective October 1, 2015, these promissory notes were canceled and the properties were transferred back to entities owned by Messrs. Kos and Tourian. See Note 11 "Related Party Transactions" and Note 16 "Subsequent Events" for additional discussion of the related party land transactions and promissory note dissolution.

MCLP Promissory Note. MCLP issued a promissory note in September 2015 for approximately $9.1 million to pay the cash portion of the contingent consideration which is due to the former owners of EFS and RPS in connection with the Services Acquisition. We are required to make monthly interest payments at an annual rate of 5.50% with principal and any unpaid interest due May 1, 2016. This promissory note replaces the March 2015 agreement, which required monthly interest payments beginning in June 2015 at an annual interest rate of 5.50% and required principal and any unpaid interest to be paid on May 1, 2016. See Note 14 "Commitments and Contingencies" for additional discussion of the contingent consideration.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. In June 2015, the maturity date of the line of credit was extended to September 2015 and was lowered to a maximum of $3.0 million with the borrowing base determined based on MCES' eligible accounts receivable. Additionally, our interest rate was increased to 4.00% over the Bank of Oklahoma Financial Corporation National Prime Rate, or 8.00% at September 30, 2015. The outstanding balance was $0.8 million at September 30, 2015 and was reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at September 30, 2015. The line of credit was paid in full in October 2015 and replaced with a new factoring arrangement. See Note 16 "Subsequent Events" for discussion of the factoring arrangement in October 2015.

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. The line of credit was paid in full in October 2015 and replaced with a new factoring arrangement. See Note 16 "Subsequent Events" for discussion of the factoring arrangement in October 2015.

19

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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 unaudited condensed consolidated 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 $3.7 million as of September 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 NGL, it also reduces the Partnership’s potential exposure to adverse price movements. The Partnership’s derivative contracts apply to only a portion of its expected production, provide only partial price protection against declines in market prices and limit the Partnership’s potential gains from future increases in market prices. Changes in the derivatives' fair values are recognized in earnings since the Partnership has elected not to designate its derivative contracts as hedges for accounting purposes.

At September 30, 2015, the Partnership's derivative contracts consisted of collars and put options, 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.

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

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
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

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
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

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

In the second quarter of 2015, we monetized certain of our open derivative contracts for the periods October 2015 through December 2015 and calendar year 2016. In October 2015, all remaining open derivatives for the periods October 2015 through calendar year 2016 were monetized for approximately $1.1 million.

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):

September 30, 2015	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,210	$	(135	)	$	1,075
Commodity derivatives - long-term assets	244		(83		)	161
Total	$	1,454	$	(218	)	$	1,236
Liabilities:
Commodity derivatives - current liabilities	$	135	$	(135	)	$	—
Commodity derivatives - long-term liabilities	83		(83		)	—
Total	$	218	$	(218	)	$	—

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.

21

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Cash receipts (payments) upon settlement (1)	$	2,442	$	(338	)	$	10,781	$	(3,750	)

__________

(1) Cash receipts upon settlement of derivative contracts for the nine months ended September 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.

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 that 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.

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Level 3 Fair Value Measurements

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

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

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

September 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	$	—	$	1,236	$	—	$	1,236
Total	$	—	$	1,236	$	—	$	1,236

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 nine months ended September 30, 2014 (in thousands):

	Nine Months Ended   September 30, 2014
Beginning balance	$	(2,517	)
Loss on derivative contracts	(2,432		)
Transfers out (1)	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 Partnership’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 Partnership’s internal valuation process, including the use of observable inputs to assess the fair value. 

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New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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 September 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 $25.0 million and $20.4 million at September 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.

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 September 30, 2015 is as follows (in thousands):

Goodwill at December 31, 2014	$	9,315
Impairment	(9,315		)
Goodwill at September 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 in the accompanying unaudited condensed consolidated statements of operations for the nine months ended September 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 nine months ended September 30, 2015 was $5.2 million. There was no amortization expense for the three months ended September 30, 2015 as a result of the impairment of our intangible assets discussed below. Amortization expense for the three and nine months ended September 30, 2014 was $9.4 million and $15.6 million, respectively. A reconciliation of the Partnership's intangible assets for the period from December 31, 2014 to September 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 September 30, 2015	$	—

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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 in the accompanying unaudited condensed consolidated statements of operations for the nine months ended September 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. The remaining proceeds were used to fund the cash portion of the Services Acquisition, for related acquisition costs, and for general corporate purposes.

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

Distributions

Distributions are declared and distributed within 45 days following the end of each quarter. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the nine months ended September 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 (1)		Total
2015
First Quarter	May 8, 2015	May 15, 2015	$	0.20	$	3,312	$	—	$	—	$	3,312
Second Quarter	N/A	N/A	$	—	$	—	$	—	$	—	$	—
Third 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
Third Quarter	October 21, 2014	November 14, 2014	$	0.585	$	9,454	$	1,290	$	91	$	10,835

__________

(1) In April 2015, all 155,102 General Partner units were canceled and converted to common units. See additional discussion in Note 11 "Related Party Transactions."

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

Our partnership agreement provides for certain incentive distributions to the general partner to the extent that the quarterly distributions exceed certain targets. These incentive distributions will result in the general partner receiving a higher proportionate share of earnings than the proportionate share of earnings allocated to the holders of common units and subordinated units. No such incentive distributions were made to our general partner as quarterly distributions that were declared, if any, by the board of directors for the first three quarters of 2015 and 2014 did not exceed the specified targets.

We made distributions per common unit of $0.20 in the first quarter of 2015 which 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 $22.7 million at September 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. In July 2015, we suspended common unit distributions.

See Note 9 "Cumulative Convertible Preferred Units" for a discussion of distributions on our Series A Preferred Units.

Noncontrolling Interest

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

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

				Marginal Percentage Interest in  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 nine months of 2015. Based on MCE's distribution amounts, the MCE Class B unitholders were entitled to distributions of approximately $0.2 million for the three months ended September 30, 2014. No distributions were due to the MCE Class B unitholders for the first or second quarter of 2014.

Equity Compensation

We may grant awards of the Partnership's common units to employees under the Partnership's Long-Term Incentive Plan ("LTIP") or Fair Market Value Purchase Plan ("FMVPP"). 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 nine months ended September 30, 2015.

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New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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. During the nine months ended September 30, 2015, the vesting of certain phantom unit awards was accelerated resulting in $1.2 million of expense.

For the three and nine months ended September 30, 2015, the Partnership recorded total equity-based compensation expense of $0.9 million and $5.3 million, respectively, compared to $1.3 million and $1.9 million for the same periods in 2014. Equity-based compensation expense for the 2015 periods 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 11.00% 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 2.00% per month until such redemption, up to a maximum rate per annum of 20.00%. The Series A Preferred Units rank senior to our common units with respect to rights upon the liquidation, dissolution or winding up of the Partnership.

Holders of our Series A Preferred Units have no voting rights except in limited circumstances. So long as any Series A Preferred Units remain outstanding, we will not, without the affirmative vote or consent of the holders of at least 66 2/3% of the Series A Preferred Units outstanding at the time, voting together as a single class with all series of parity securities with similar voting rights have been conferred and are exercisable, given in person or by proxy, either in writing or at a meeting: (a) authorize or create, or increase the authorized or issued amount of, any class or series of senior securities or reclassify any of our authorized equity securities into units of senior securities, or create, authorize or issue any obligation or security convertible into or evidencing the right to purchase any senior securities; (b) consummate a spin-off prior to the earlier to occur of (i) December 31, 2016 or (ii) the first day after which 2100 Energy has caused one or a series of transactions to occur whereby one or more third parties have transferred $100.0 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.

27

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

We received net proceeds, including proceeds from the exercise of the underwriters' option, of approximately $44.5 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 September 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. A quarterly distribution of $0.6875 per Series A Preferred Unit, totaling $1.3 million, was due to be paid on October 15, 2015. Due to the borrowing base deficiency under our credit facility, as discussed in Note 3 "Debt," we were prevented from paying these distributions. These distributions were accrued and included in accounts payable and accrued liabilities in the accompanying unaudited condensed consolidated balance sheet at September 30, 2015. If we do not pay distributions in full on any two distribution payment dates (whether consecutive payment dates or not), the per annum distribution rate will increase by an additional 2.00% per quarterly distribution not paid, up to a maximum rate per annum of 20.00% per Series A Preferred Unit on and after the day following such second distribution payment date. If all accrued distributions are paid, the distribution rate returns to 11.00%.

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 nine months ended September 30, 2015, 3,818,120 and 7,299,453 weighted average common units, respectively, issuable upon conversion of our Series A Preferred Units at the initial conversion rate and LTIP awards of 34,873 and 34,104 common units, respectively, were excluded from the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of September 30, 2014. Therefore, basic and diluted earnings per unit are the same for the three and nine months ended months ended September 30, 2014.

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

	Three Months Ended   September 30, 2015						Nine Months Ended   September 30, 2015
	Common Units			Subordinated Units			Common Units			Subordinated Units			General Partner (1)
Net loss attributable to common, subordinated, and general partner units	$	(55,689	)	$	(7,447	)	$	(202,768	)	$	(28,090	)	$	(470	)
Weighted average units outstanding	16,488			2,205			16,431			2,205			155
Basic and diluted loss per unit	$	(3.38	)	$	(3.38	)	$	(12.34	)	$	(12.74	)	$	(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.

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Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

New Dominion. New Dominion is an exploration and production operator wholly-owned by Mr. Chernicky. Pursuant to various development agreements with the Partnership, New Dominion is currently contracted to operate the Partnership’s existing wells. In 2014, the Partnership, along with other working interest owners, reimbursed New Dominion for our proportionate share of costs incurred to construct a gas gathering system that 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 Partnership had no leasehold cost obligations at September 30, 2015. As of December 31, 2014, the Partnership had leasehold cost obligations of $0.4 million which were classified as a long-term liability in the accompanying unaudited condensed consolidated balance sheet.

29

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Producing overhead and supervision charges	$	828	$	624	$	2,200	$	2,080
Drilling and completion supervision charges	528		60		704		230
Saltwater disposal fees	279		260		829		1,075
Total expenses incurred	$	1,635	$	944	$	3,733	$	3,385

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 September 30, 2015 and December 31, 2014, the Partnership had related party receivables, net from New Dominion of $3.6 million and $3.4 million, respectively. See Note 14 "Commitments and Contingencies" for discussion of litigation with our contract operator. As a result of the ongoing litigation with New Dominion, a reserve of $1.2 million on the outstanding net receivable was recorded and is reflected in the related party receivable, net balance at September 30, 2015.

New Source Energy GP, LLC. Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three and nine months ended September 30, 2014, the amount paid to our general partner for such reimbursements was $0.5 million and $1.1 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 September 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.

During 2014 the Partnership expended approximately $1.2 million to construct buildings on a parcel of land that was owned by an entity wholly-owned by Messrs. Kos and Tourian. These expenditures were made in contemplation of purchasing the land, which occurred in 2015. 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 entity that sold MCES land in Karnes County, the portion of the land acquired from Mr. Kos was recorded at his carrying value. The $0.2 million difference between Mr. Kos' carrying value and the purchase price was reflected as a reduction to equity.

In October 2015, the Partnership entered into an agreement to transfer these parcels of land back to the respective selling entities in exchange for canceling the notes, together with accumulated interest. The closing is contemplated for November 2015. See Note 3 "Debt" and Note 16 "Subsequent Events" for additional discussion on these notes payable and the cancellation thereof.

Disposition. In September 2015, MCES received a deposit of $0.7 million toward the sale of certain of its equipment to an entity wholly-owned by Messrs. Kos and Tourian. Total proceeds from the sale, completed in October 2015, were approximately $1.0 million. This transaction was approved by the Conflicts Committee of the board of directors of our general partner. MCES also agreed to continue to rent this equipment to customers as agent for the purchasing entity in exchange for 20% of the revenue generated from any such rental. See Note 16 "Subsequent Events" for additional discussion related to this disposition.

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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 Partnership 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 NGL as of March, 31, 2015, June 30, 2015 and September 30, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015, $32.9 million during the second quarter of 2015 and $49.1 million during the third quarter of 2015. Continued low levels or declines in oil, natural gas and NGL prices subsequent to September 30, 2015 are expected to result in additional ceiling test write downs in the fourth 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):

	September 30, 2015			December 31, 2014
Vehicles and transportation equipment	$	15,826		$	15,891
Machinery and equipment	53,223			44,441
Office furniture and equipment	981			1,069
Iron	7,895			12,258
Total	77,925			73,659
Less: accumulated depreciation and impairment	(12,140		)	(4,773		)
	65,785			68,886
Land	1,200			—
Property and equipment, net	$	66,985		$	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 of $6.3 million in the second quarter of 2015 on its oilfield services equipment. No additional impairment was required in the third quarter of 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 September 30, 2015 is as follows (in thousands):

Asset retirement obligation at December 31, 2014	$	3,681
Liability incurred upon acquiring and drilling wells	—
Accretion	203
Asset retirement obligation at September 30, 2015	3,884
Less current portion	119
Asset retirement obligations, net of current	$	3,765

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, the Partnership is required to make monthly interest payments at an annual rate of 5.50% 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. In September 2015, the agreement concerning payment of the cash portion was replaced with a promissory note issued by MCLP in the amount of $9.1 million. See Note 3 "Debt" for additional discussion on the promissory note. At September 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, NSEC 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. The plaintiffs also 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.

Hearings on certain motions to dismiss filed by the defendants were held on August 5, 2015 and September 11, 2015. On September 15, 2015, the parties agreed to stay this proceeding pending settlement discussions.

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. On September 15, 2015, the parties agreed to stay this proceeding pending settlement discussions.

The Partnership and plaintiffs have engaged in settlement discussions; however, a settlement has not been reached. Under a settlement agreement, it is possible that the Partnership could recognize a gain or loss on the ultimate transaction. Information necessary to determine such a gain or loss is not currently available. If a settlement is not reached, the Partnership plans to continue to vigorously pursue its claims. The Partnership believes that plaintiffs owe it the amounts it has recorded, that plaintiffs have the ability to pay these amounts, and that plaintiffs’ claims against the Partnership are without merit. However, as a result of the ongoing litigation with New Dominion, a reserve of $1.2 million on the outstanding net receivable was recorded and is reflected in the related party receivable, net balance at September 30, 2015.

33

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

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

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

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

Fair Labor Standards Act Litigation. EFS and RPS are involved in two separate, yet similar lawsuits in which the plaintiff claims he and other similarly situated flow hands or “flow backs” were misclassified as independent contractors, as opposed to employees with overtime entitlement, in violation of the Fair Labor Standards Act (“FLSA”) and in violation of various state laws. Both cases are brought by the same individual plaintiff and are against EFS and RPS, respectively. The same law firm represents the plaintiffs in both cases. The Partnership has not been added as a named party in either of these cases, but it could potentially be added in the future.

Specifically, these matters are:

•Jeremy Saenz, on Behalf of Himself and All Others Similarly Situated v. Rod’s Production Services, LLC: This is a purported collective action and class action filed on June 2, 2015 in the United States District Court for the District of New Mexico. The plaintiff claims that RPS misclassified him as an independent contractor under the FLSA and New Mexico state law. The plaintiff also filed a motion to amend to add state law claims under Pennsylvania and Ohio wage laws. The plaintiff seeks unpaid overtime for the time he worked as a misclassified independent contractor. The court conditionally certified the collective action under the FLSA and the opt-in period closed on July 15, 2015. The parties dispute how many proper opt-ins have been filed, but the class will range between 64 and 80 opt-in plaintiffs, including the named plaintiff. The parties are beginning discovery. The parties have a scheduling order from the court. Discovery cutoff is May 16, 2016 and trial is scheduled for February 2017.

•Jeremy Saenz, on Behalf of Himself and All Others Similarly Situated v. Erick Flowback Services, LLC: This is a purported collective action and class action filed on June 10, 2015 in the United States District Court for the Western District of Oklahoma. The plaintiff claims that EFS misclassified him as an independent contractor under the FLSA, and Ohio and Pennsylvania state laws. The plaintiff seeks unpaid overtime for the time he worked as a misclassified independent contractor. The court conditionally certified the collective action and the opt-in period closed on August 11, 2015. The parties dispute the number of proper opt-in plaintiffs, but the class will be between 76 and 100 plaintiffs, including the named plaintiff. The parties had a scheduling conference on September 16, 2015. Currently, the parties are briefing the scope of discovery. The court has not yet entered a scheduling order.

The Partnership recorded a reserve for the above Fair Labor Standards Act Litigation of $1.5 million, reflective of the facts and circumstances as currently known. The actual loss may differ from the established reserve. On October 28, 2015, the parties entered into an Agreement to Stay Proceedings that stays the current litigation and provides the parties with a 60-day mediation period, unless extended by the parties.

34

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

On October 21, 2015, a class action complaint was filed in the Supreme Court of the State of New York against the Partnership, certain current and former directors of the Partnership’s general partner and certain investment banking firms in the case styled Enrico Vaccaro vs. New Source Energy Partners L.P., Kristian B. Kos, Terry L. Toole, Dikran Tourian, Richard D. Finley, V. Bruce Thompson, John A. Raber, Stifel, Nicholas & Company, Inc., Robert W. Baird & Co. Inc., Janney Montgomery Scott LLC, Oppenheimer & Co. Inc., and Wunderlich Securities, Inc.  The complaint asserts a state securities class action on behalf of a putative class consisting of persons or entities who purchased or otherwise acquired the Partnership's Series A Preferred Units pursuant to the related prospectus and prospectus supplement, seeking to recover damages allegedly caused by the defendants’ violations of the federal securities laws under Sections 11, 12(a)(2) and 15 of the Securities Act of 1933 (the "Securities Act").  The complaint alleges that the defendants made materially false and misleading statements regarding the Partnership’s business and operations because such statements failed to properly reflect the impact of certain actions by the Partnership’s contract operator on the Partnership’s financial condition.  The Partnership and the other defendants associated with the Partnership intend to defend this lawsuit vigorously. 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 plaintiff’s claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action.

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.

35

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 September 30, 2015
Revenues	$	3,824		$	16,281		$	20,105
Direct operating expenses	4,173			13,777			17,950
Segment margin	(349		)	2,504			2,155
Depreciation, depletion, amortization and accretion	2,985			2,414			5,399
Impairment	49,141			—			49,141
General and administrative expenses	3,721			4,848			8,569
Loss from operations	$	(56,196	)	$	(4,758	)	$	(60,954	)
Capital expenditures (1)	$	171		$	899		$	1,070
Three Months Ended September 30, 2014
Revenues	$	15,561		$	40,863		$	56,424
Direct operating expenses	5,562			24,315			29,877
Segment margin	9,999			16,548			26,547
Depreciation, depletion, amortization and accretion	6,834			11,003			17,837
General and administrative expenses	7,354			6,431			13,785
Loss from operations	$	(4,189	)	$	(886	)	$	(5,075	)
Capital expenditures (1)	$	824		$	3,735		$	4,559

__________

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

36

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

	Exploration and Production			Oilfield Services			Total
Nine Months Ended September 30, 2015
Revenues	$	15,710		$	66,596		$	82,306
Direct operating expenses	12,631			51,473			64,104
Segment margin	3,079			15,123			18,202
Depreciation, depletion, amortization and accretion	11,399			12,479			23,878
Impairment	125,165			66,784			191,949
General and administrative expenses	10,544			16,930			27,474
Loss from operations	$	(144,029	)	$	(81,070	)	$	(225,099	)
Capital expenditures (1)	$	7,880		$	3,076		$	10,956
At September 30, 2015
Total assets	$	54,426		$	85,233		$	139,659
Nine Months Ended September 30, 2014
Revenues	$	51,130		$	59,539		$	110,669
Direct operating expenses	16,252			34,849			51,101
Segment margin	34,878			24,690			59,568
Depreciation, depletion, amortization and accretion	19,692			17,856			37,548
General and administrative expenses	13,220			9,615			22,835
Income (loss) from operations	$	1,966		$	(2,781	)	$	(815	)
Capital expenditures (1)	$	19,284		$	6,726		$	26,010
At December 31, 2014
Total assets	$	199,178		$	176,368		$	375,546

__________

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

16.  Subsequent Events

In the first quarter of 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. In October 2015, as approved by the Conflicts Committee of the board of our general partner, the Partnership entered into an agreement to transfer the three parcels of land, together with approximately $1.9 million in buildings constructed on the Ector County, Texas parcel, back to the respective selling entities. In return for the transfer of land and buildings valued at approximately $3.3 million, the Partnership's promissory notes of $1.4 million, together with accrued interest, will be canceled and the Partnership expects to lease the building located on the Ector County, Texas land at a reduced rate. See Note 3 "Debt" and Note 11 "Related Party Transactions" for additional discussion on these notes payable and the acquisitions.

In October 2015, MCES completed the sale of certain of its operating equipment for $1.0 million in total proceeds to an entity wholly-owned by Messrs. Kos and Tourian. A loss of approximately $0.3 million was recorded in the fourth quarter of 2015 as a result of this transaction. MCES also agreed to continue to rent this equipment to customers as agent for the purchasing entity in exchange for 20% of the revenue generated from any such rental.

37

New Source Energy Partners L.P.

Notes to Condensed Consolidated Financial Statements - continued

(Unaudited)

On September 9, 2015, the Partnership was notified by the New York Stock Exchange (the “NYSE”) that it was not in compliance with the continued listing standards set forth in Sections 802.01B and 802.01C of the NYSE Listed Company Manual because the Partnership failed to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15.0 million for its common units and the average closing price of the Partnership’s common units was less than $1.00 over a consecutive 30 trading-day period. On October 5, 2015, the NYSE filed a Form 25 with the Securities and Exchange Commission (the “SEC”) to delist our common units. Since then, our common units have been quoted on the OTC Market Group under the ticker symbol “NSLP.”

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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 our business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with our accompanying unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly Report, as well as our audited consolidated financial statements and the accompanying notes included in the 2014 Form 10-K. Our discussion and analysis includes the following subjects:

•Overview;

•Results by Segment;

•Results of Operations;

•Liquidity and Capital Resources; and

•Critical Accounting Policies and Estimates.

The financial information with respect to the three and nine months ended September 30, 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 Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 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.

Outlook

Beginning in the second half of 2014 and throughout 2015, the oil and natural gas market has 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 2015. As compared to the third quarter of 2014 and the first nine months of 2014, the WTI index average prices for oil declined 52% and 48%, 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 and third quarters of 2015.

39

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 NGL 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 NGL that we can produce economically.

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 throughout 2015, significant declines in the price of oil, natural gas and NGL 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. Additionally, the Oklahoma Corporation Commission issued directives in the second and third quarters of 2015 to restrict the injection of high volumes of water into formations below the Arbuckle formation into the crystalline basement. Our contract operator was required to reduce salt water injection volumes for its disposal wells located in that area which has resulted in reduced levels of production in the Southern Dome. We expect the reduced level of production to continue unless other economically feasible options to dispose of the salt water are identified and pursued.

As an oil, natural gas, and NGL producer, we face the challenge of natural production declines and volatile commodity prices. 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. Based on current commodity prices and continued increases in costs by our contract operator, we do not anticipate drilling any new wells in 2015 or 2016.

As a non-operated working interest owner, we also face the additional challenge of operating expenses imposed by our contract operator. Although we monitored our costs and discussed expenses with our contract operator, we saw a significant rise in our lease operating expenses per Boe in 2014 and throughout 2015, as compared to previous years, and expect the higher costs to continue through the remainder of 2015 and into 2016. 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 reduced drilling activity, we estimate revenue, operating income and cash flow from operations for our exploration and production business will continue to 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. Additionally, no drilling activities are planned for 2015 or early 2016. 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.

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 can cause our reserves to become uneconomic, which could result in an impairment of our full cost pool. 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. Based on the 12-month average prices of oil, natural gas and NGL as of March, 31, 2015, June 30, 2015, and September 30, 2015, we recorded a ceiling test impairment of oil and natural gas properties of $43.1 million during the first quarter of 2015, $32.9 million during the second quarter of 2015, and $49.1 million during the third quarter of 2015. We expect to incur a further ceiling test impairment in the fourth quarter of 2015 assuming commodities prices do not increase dramatically. While it is difficult to project future impairment charges in light of numerous variables involved, the following analysis using basic assumptions is provided to illustrate the impact of lower commodities pricing on impairment charges and proved reserves volumes. If we reduce the 12-month average price for natural gas by $1.00 per MMBtu, the 12-month average price for oil by $6.00 per barrel and the 12-month NGL price by $1.80 per barrel, while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves and present value of our future net revenues would have been approximately 650 MBoe and $16 million, respectively, lower, based on the price sensitivity generated from an internal evaluation of our proved reserves.

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Our credit facility is subject to a borrowing base that 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 $57.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions and with consideration of the settlement of a portion of our derivative contracts prior to their contractual maturity. As of September 30, 2015, we had $49.0 million in outstanding borrowings with no available borrowing capacity. As a result of our semi-annual redetermination on October 9, 2015, our borrowing base was reduced to $24.0 million due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. The reduced borrowing base results in a borrowing deficiency of $25.0 million. Our credit facility requires any deficiency to be settled in full within 30 days or in equal installments over a 90-day period. During a deficiency, an additional 2.00% is applied to the interest rate on the outstanding balance under the credit facility, not to exceed the maximum rate as defined in the credit agreement. Our lenders also have the option to cause the liquidation of collateral in order to satisfy the deficiency. We are in discussions with the lenders under the credit facility and expects to enter into a forbearance arrangement soon.

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 nearly 63% 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 September 30, 2015, the United States rig count had fallen by approximately 1,000 rigs, or 55%, compared to the 2014 year-end rig count. During the second quarter of 2015, the North American rig count decline began to slow but continued to decline further through the third quarter of 2015 to 809 rigs at September 30, 2015. For the remainder of the year, we expect unfavorable market conditions to continue and North American rig counts to remain at these lower counts.

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 commodity price levels. In response to the decline in commodity prices noted in the fourth quarter of 2014 and continuing throughout 2015, our exploration and production customers have significantly reduced drilling activity and planned capital expenditures. 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 decline in commodity prices, the market for oilfield services has experienced downward pricing pressure. We, in turn, offered reduced rates for our services in an effort to retain our customer base and maintain our market share until commodity prices improve to more favorable levels.

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 initiated certain cost reductions during the first quarter of 2015 with additional cost reductions becoming effective in the second and third quarters of 2015. To the extent cost cutting efforts are not fully realized, the losses on our oilfield services could increase. Maintenance capital expenditures for 2015 are expected to be lower than in 2014, and any growth capital expenditures in 2015 will be dependent on our customers' drilling activity levels and available cash flow.

Corporate. We have taken steps to address potential shortfalls in cash flow from operations necessary to fund our investing and financing activities. In May 2015, we completed a public offering of 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 $44.5 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.

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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 twelve-month period ending September 30, 2016. We anticipate that we may incur additional operating losses in the next twelve months. Historically, we have financed our operations through equity issuances and debt financings; however, management is actively pursuing additional sources of capital. We currently do not have any arrangements for financing and we can provide no assurance to investors that we will be able to find such financing if required. 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. If we are unable to secure financing, refinance our debt, or reach a solution with our lenders, then we expect that we will not be able to pay our obligations as they become due.

Management is actively pursuing additional sources of capital. We, however, are dependent upon our ability to secure equity or debt financing or monetize certain of our oilfield services assets and there are no assurances that we will be successful in such endeavors. Possible sources of capital include the pursuit of additional financing for our oilfield services business and divestiture of assets.

Our ability to obtain capital or 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 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 equity or debt transactions and the timing of these transactions 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.

Our ability to continue as a going concern depends on our ability to execute our 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 the credit facility and 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. Additionally, the reduction in the borrowing base on our credit facility in October 2015 has resulted in a deficiency of $25.0 million. Our credit facility requires any deficiency to be settled in full within 30 days or in equal installments over a 90-day period. Our lenders also have the option to cause the liquidation of collateral in order to satisfy the deficiency. If we are unable to secure financing, refinance our debt, or reach a solution with our lenders, then we expect that we will not be able to pay our obligations as they become due. In an event of default, the administrative agent may, and at the request of the majority of lenders, declare the outstanding balance under the credit facility immediately due and payable. The Partnership is in discussions with the lenders under the credit facility and expects to enter into a forbearance arrangement soon.

These factors raise substantial doubt about the Partnership’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 necessary funds to continue as a going concern. We, however, are dependent upon our ability to secure equity or debt financing or monetize certain of its oilfield services assets and there are no assurances that we will be successful in such endeavors.

Recent Developments

Ownership of our General Partner. On April 27, 2015, we entered into a purchase agreement among us, 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 ours 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 us 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), we will also transfer all of our 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, we will own all of the equity interests in MCLP except for the general partner interest and the Class B units. We cannot guarantee the transactions described above will occur in a timely manner, if at all.

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

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 us 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.

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 11.00% 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 2.00% per month until redeemed, up to a maximum rate per annum of 20.00%. 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 $44.5 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. A quarterly distribution of $0.6875 per Series A Preferred Unit, totaling $1.3 million, was due to be paid on October 15, 2015. Due to the borrowing base deficiency under our credit facility, we were prevented from paying these distributions. These distributions were accrued and included in Series A Cumulative Convertible Preferred Units in the accompanying unaudited condensed consolidated balance sheet as of September 30, 2015. If we do not pay distributions in full on any two distribution payment dates (whether consecutive payment dates or not), the per annum distribution rate will increase by an additional 2.00% per quarterly distribution not paid, up to a maximum rate per annum of 20.00% per Series A Preferred Unit on and after the day following such second distribution payment date. If all accrued distributions are paid, the distribution rate will return to 11.00%.

 Credit Facility Redetermination. As a result of our semi-annual redetermination on October 9, 2015, our borrowing base was reduced to $24.0 million due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. The reduced borrowing base results in a $25.0 million borrowing deficiency. Our credit facility requires any deficiency to be settled in full within 30 days or in equal installments over a 90-day period. During a deficiency, an additional 2.00% is applied to the interest rate on the outstanding balance under the credit facility, not to exceed the maximum rate as defined in the credit agreement. Our lenders also have the option to cause the liquidation of collateral in order to satisfy the deficiency. The Partnership is in discussions with the lenders under the credit facility and expects to enter into a forbearance arrangement soon.

Delisting from the NYSE. On September 9, 2015, we were notified by the NYSE that we were not in compliance with the continued listing standards set forth in Sections 802.01B and 802.01C of the NYSE Listed Company Manual because we failed to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15.0 million for our common units and the average closing price of our common units was less than $1.00 over a consecutive 30 trading-day period. On October 5, 2015, the NYSE filed a Form 25 with the SEC to delist our common units. Since then, our common units have been quoted on the OTC Market Group under the ticker symbol “NSLP.”

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.

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Oil and Natural Gas Operations

• produced volumes;

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

• lease operating expenses; and

• 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, (gain) loss 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.

Results by Segment

We operate in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent our 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 our 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 our business segments. The results of our business segments for the three and nine months ended September 30, 2015 and 2014 are discussed below.

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Exploration and Production Segment

We generate a portion of our consolidated revenues and cash flow from the production and sale of oil, natural gas and NGL. The exploration and production segment’s revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGL and on our 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 NGL 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 NGL. 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 our exposure to price fluctuations, we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in "Item 3. Quantitative and Qualitative Disclosures About Market Risk."

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Results (in thousands):
Oil sales	$	566		$	3,798		$	3,906		$	12,146
Natural gas sales	1,175			3,711			4,422			12,928
NGL sales	2,083			8,052			7,382			26,056
Total revenues	3,824			15,561			15,710			51,130
Production expenses	3,976			4,894			11,841			13,913
Production taxes	197			668			790			2,339
Total segment margin	(349		)	9,999			3,079			34,878
Depreciation, depletion, amortization and accretion	2,985			6,834			11,399			19,692
Impairment	49,141			—			125,165			—
General and administrative	3,721			7,354			10,544			13,220
Operating (loss) income	$	(56,196	)	$	(4,189	)	$	(144,029	)	$	1,966
Production volumes:
Oil (Bbls)	9,815			39,990			83,459			124,296
Natural gas (Mcf)	525,171			960,434			1,793,145			2,876,478
NGL (Bbls)	168,286			227,439			530,697			674,717
Total production volumes (Boe)	265,630			427,501			913,014			1,278,426
Average daily production volumes (Boe)	2,887			4,647			3,344			4,683
Average price (excluding derivatives):
Oil (per Bbl)	$	57.67		$	94.97		$	46.80		$	97.72
Natural gas (per Mcf)	$	2.24		$	3.86		$	2.47		$	4.49
NGL (per Bbl)	$	12.38		$	35.40		$	13.91		$	38.62
Total (per Boe)	$	14.40		$	36.40		$	17.21		$	39.99
Average production costs (per Boe)(1)	$	14.97		$	11.45		$	12.97		$	10.88

__________

(1) Includes lease operating expense and workover expense.

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Revenue

Revenues from our exploration and production segment for the three and nine months ended September 30, 2015 decreased $11.7 million, or 75.4%, and $35.4 million, or 69.3%, respectively, compared to the same periods in 2014. The decrease in revenues for both the three and nine-month periods are primarily due to lower commodity prices and lower production. The average price per Boe received on our combined production decreased $22.00 and $22.78 in the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014.

Combined production decreased 161,871 Boe, or 37.9%, and 365,412 Boe, or 28.6%, in the three and nine months ended September 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 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 our unaudited condensed consolidated financial statements in Item 1. "Financial Statements" of this report.

Production expenses decreased $0.9 million, or 18.8%, and $2.1 million, or 14.9%, for the three and nine months ended September 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 primarily due to the required additional costs associated with the saltwater disposal wells to comply with Oklahoma Corporation Commission directives noted above. More of our wells required submersible pumps and other repairs in 2015 and we incurred higher operator fees in 2015. As a result of these factors, production expenses increased $3.52 per Boe and $2.09 per Boe for the three and nine months ended September 30, 2015, respectively, compared to the same periods in 2014.

Production taxes. Production taxes decreased $0.5 million and $1.5 million, respectively, in the three and nine months ended September 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 $3.8 million and $8.3 million for the three and nine months ended September 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 NGL as of September 30, 2015, we recorded an impairment of our oil and natural gas properties of $49.1 million during the third 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 nine months ended September 30, 2015 totaled $125.2 million. No impairment was considered necessary during the nine months ended September 30, 2014.

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General and administrative. General and administrative expense decreased $3.6 million for the three months ended September 30, 2015 compared to the same period in 2014 primarily due to cost reductions implemented in the second quarter of 2015 and $5.4 million that was included in 2014 for the change in fair value of contingent consideration on certain acquisitions. General and administrative expense increased $2.7 million for the nine months ended September 30, 2015 from the comparable period in 2014 primarily due to the issuance of equity awards in the first quarter of 2015 and $1.5 million of equity-based compensation related to awards that had accelerated vesting. Partially offsetting the increases are reductions to certain general and administrative expenses as part of cost cutting efforts we implemented in the second quarter of 2015.

Oilfield Services Segment

Our oilfield services segment was established with the MCE Acquisition 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 our 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.

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

	Three Months Ended   September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Results (in thousands):
Oilfield service revenue	$	16,281		$	40,863		$	66,596		$	59,539
Cost of providing oilfield services	13,777			24,315			51,473			34,849
Total segment margin	2,504			16,548			15,123			24,690
Depreciation and amortization	2,414			11,003			12,479			17,856
Impairment	—			—			66,784			—
General and administrative	4,848			6,431			16,930			9,615
Operating loss	$	(4,758	)	$	(886	)	$	(81,070	)	$	(2,781	)

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 $16.3 million and $66.6 million for the three and nine months ended September 30, 2015, respectively. The decrease of $24.6 million in the three-month period ended September 30, 2015 over the same period in 2014 is primarily due to the reduced transaction volumes and the reduced pricing provided to customers as a result of lower drilling and completion activity in 2015. The increase of $7.1 million in the nine-month period ended September 30, 2015 over the same period in 2014 is due to the Services Acquisition completed in June 2014, partially offset by a reduction in services provided to customers as a result of lower drilling and completion activity in 2015.

Operating Expenses

Cost of providing oilfield services. Cost of providing oilfield services includes direct and indirect labor and other service costs. The cost of providing oilfield services for the three months ended September 30, 2015 decreased $10.5 million mainly due to cost cutting efforts, discounts received from our vendors and reduced activity as a result of lower demand for our services. The cost of providing oilfield services for the nine months ended September 30, 2015 increased $16.6 million over the same period in 2015 primarily due to the Services Acquisition completed in June 2014. Costs of providing oilfield services associated with operations from the Services Acquisition in 2015 were $38.5 million and were partially offset by cost cutting measures implemented in the second quarter of 2015. Due to certain fixed costs, such as field location expense, the decrease in cost of providing oilfield services is not in direct proportion to the decrease in revenue noted for the same period.

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Depreciation and amortization. Depreciation and amortization expense decreased $8.6 million and $5.4 million compared to the same periods in 2014 primarily as a result of no amortization recorded on intangible assets in the second and third quarters of 2015. As discussed below, our intangible assets were fully impaired in 2015.

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, we 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 in the second quarter of 2015. There was no impairment of goodwill recorded for the three or nine months ended September 30, 2014.

In the second quarter of 2015, we 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 in the second quarter of 2015. There was no impairment of oilfield services intangible assets recorded for the three or nine months ended September 30, 2014.

Due to the continued depressed commodity environment and the impact on the demand for oilfield services, we analyzed our 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, we recorded an impairment on our oilfield services equipment of approximately $6.3 million in the second quarter of 2015. There was no impairment of oilfield services equipment in the three or nine months ended September 30, 2014.

General and administrative. General and administrative expense consists of non-field employee compensation, selling expenses, professional fees and occupancy costs. General and administrative expense for the three months ended September 30, 2015 decreased $1.6 million compared to the same period in 2014 mainly due to cost reduction efforts implemented in the second quarter of 2015. General and administrative expense for the nine months ended September 30, 2015 compared to the same period in 2014 increased $7.3 million mainly due to equity compensation and $12.5 million of general and administrative expenses associated with the Services Acquisition.

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

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Results of Operations

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2015			2014			2015			2014
	(in thousands)
Operating loss	$	(60,954	)	$	(5,075	)	$	(225,099	)	$	(815	)
Other income (expense):
Interest expense	(832		)	(1,458		)	(3,929		)	(3,442		)
Gain (loss) on derivative contracts, net	1,794			3,768			1,951			(760		)
Gain on investment in acquired business	—			—			—			2,298
Other (expense) income	(1,536		)	11			(1,479		)	18
Net loss	$	(61,528	)	$	(2,754	)	$	(228,556	)	$	(2,701	)

Other Income/Expense

Interest expense. Interest expense decreased $0.6 million for the three months ended September 30, 2015 compared to the same period in 2014 primarily due to the lower borrowing base in 2015. Interest expense increased $0.5 million for the nine months ended September 30, 2015 compared to the same period in 2014 primarily due to the write-off of a proportionate amount of debt issuance costs related to the second quarter reduction of our borrowing base, partially offset by lower interest expense due to a lower borrowing base.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Cash receipts (payments) upon settlement (1)	$	2,442	$	(338	)	$	10,781	$	(3,750	)

__________

(1) Cash receipts upon settlement of derivative contracts for the three and nine months ended September 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.

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.

Other (expense) income. The $1.5 million increase in other (expense) income for the three and nine months ended September 30, 2015 was primarily due to the write-off of approximately $1.0 million in previously deferred offering costs in the third quarter of 2015.

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 for the three and nine months ended September 30, 2015 and 2014 is provided below (in thousands):

	Three Months Ended   September 30,						Nine Months Ended   September 30,
	2015			2014			2015			2014
Reconciliation of adjusted EBITDA to net loss:
Net loss	$	(61,528	)	$	(2,996	)	$	(228,556	)	$	(2,943	)
Interest expense	832			1,458			3,929			3,442
Depreciation, depletion and amortization	5,329			17,760			23,675			37,329
Accretion expense	70			77			203			219
Impairment	49,141			—			191,949			—
Non-cash compensation expense	929			1,262			5,251			1,906
Transaction fees	—			392			1,052			3,624
Gain on investment in acquired business	—			—			—			(2,298		)
(Gain) loss on derivative contracts, net	(1,794		)	(3,768		)	(1,951		)	760
Cash received (paid) on settlement of derivative contracts (1)	2,442			(338		)	10,781			(3,750		)
Settlement reserve	1,500			—			1,500			—
Bad debt expense	1,397			—			1,475			—
Write-off of deferred offering costs	1,005			—			1,005			—
Other	1,697			41			2,771			41
Change in fair value of contingent consideration	—			5,404			—			4,493
Adjusted EBITDA	$	1,020		$	19,292		$	13,084		$	42,823

__________

(1) The three-month period ended September 30, 2015 includes $1.1 million related to early settlement of our derivative contracts. The nine-month period ended September 30, 2015 includes $5.0 million related to early settlement of our derivative contracts.

A reconciliation of Adjusted EBITDA to net loss for our exploration and production and oilfield services segments for the three and nine months ended September 30, 2015 is provided below (in thousands):

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	Three Months Ended   September 30, 2015						Nine Months Ended   September 30, 2015
	E&P			OFS			E&P			OFS
Reconciliation of adjusted EBITDA to net loss:
Net loss	$	(55,386	)	$	(6,142	)	$	(145,163	)	$	(83,393	)
Interest expense	317			515			2,418			1,511
Depreciation, depletion and amortization	2,916			2,413			11,196			12,479
Accretion expense	70			—			203			—
Impairment	49,141			—			125,165			66,784
Non-cash compensation expense	11			918			726			4,525
Transaction fees	—			—			1,052			—
Gain on derivative contracts, net	(1,794		)	—			(1,951		)	—
Cash received on settlement of derivative contracts	2,442			—			10,781			—
Settlement reserve	—			1,500			—			1,500
Bad debt expense	1,203			194			1,203			272
Write-off of deferred offering costs	—			1,005			—			1,005
Other	1,031			666			1,663			1,108
Adjusted EBITDA	$	(49	)	$	1,069		$	7,293		$	5,791

Liquidity and Capital Resources

Our primary sources of liquidity and capital resources have historically been cash flows generated by operating activities, borrowings under our credit facility and other debt instruments, and issuing equity securities in connection with acquisitions and capital markets offerings. Our primary uses of capital have been for the acquisition and development of oil and natural gas properties, the acquisition of our oilfield services business, working capital needs and distributions of available cash to our unitholders.

Our ability to fund our capital expenditures and satisfy our other obligations when due has been negatively impacted by significant decreases in the market price for oil, natural gas and NGLs during the fourth quarter of 2014 with continued weakness through the third quarter of this year. The decrease in the market price for our production directly reduces our operating cash flow. While we have historically used hedging arrangements to reduce our exposure to fluctuations in the prices of oil, natural gas and NGLs, currently, none of our production is currently hedged, and we do not have cash resources to hedge our production for future periods. In addition, the decrease in the market price for our production indirectly impacts our other sources of potential liquidity. Lower market prices for our production has resulted in, and may result in future, lower borrowing capacity under our credit facility and may result in higher borrowing costs from other potential sources of debt financing as our borrowing capacity and borrowing costs are generally related to the value of our estimated proved reserves.

As a result of the decline in commodity prices, the market for oilfield services has experienced downward pricing pressure. We, in turn, offered reduced rates for our services in an effort to retain our customer base and maintain our market share until commodity prices improve to more favorable levels. 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 measures to address the impact of declines in our revenue and cash flows from operations. Such cost cutting measures include seeking discounts from our vendors, reductions to personnel and compensation, and adjusting planned capital expenditures. We initiated certain cost reductions during the first quarter of 2015 with additional cost reductions becoming effective in the second and third quarters of 2015. Maintenance capital expenditures for 2015 are expected to be lower than in 2014, and any growth capital expenditures in 2015 will be discretionary and based on our customers' drilling activity levels.

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In addition to continued volatility in commodity prices and declining revenues from our oilfield services business, our liquidity and capital resources have been and continues to be limited by the withholding of revenue from our working interest by New Dominion, our contract operator. During 2015, New Dominion has withheld all revenue from our sold oil and natural gas production in satisfaction of certain 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 include certain of New Dominion’s officers as well as David Chernicky as defendants. On September 15, 2015, the parties agreed to stay this proceeding pending settlement discussions. In light of continued negative volatility in commodity prices and the decline in revenues from our oilfield services business, 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.

Our credit facility is a four-year, senior secured credit facility set to mature in February 2017. 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 (i) payment of the total amount of the excess within 30 days or in equal monthly installments over a three-month period; (ii) a lien on oil and gas properties we own for sufficient consideration; or (iii) 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.

In the second quarter of 2015, our borrowing base was lowered from $90.0 million to $57.0 million based on our estimated oil, natural gas and NGL reserves. As a result of our semi-annual redetermination of our credit facility on October 9, 2015, our borrowing base was reduced to $24.0 million due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. Our reserves were lower than expected due to problems encountered in the Southern Dome area with the injection wells negatively impacting production while still incurring high lease operating expenses. The reduced borrowing base results in a borrowing deficiency of $25.0 million. We do not currently have sufficient cash resources to repay or additional collateral to cure the borrowing base deficiency. Any deficiency under the credit facility is required to be settled in full within 30 days or in equal installments over a 90-day period. During a deficiency, an additional 2.00% is applied to the interest rate on the outstanding balance under the credit facility, not to exceed the maximum rate as defined in the credit agreement. Our lenders also have the option to cause the liquidation of collateral in order to satisfy the deficiency. In an event of default, the administrative agent may, and at the request of the majority of lenders, declare the outstanding balance under the credit facility immediately due and payable.

We are currently engaged in discussions with the lenders under our credit facility regarding a waiver or forbearance with respect to any event of default that may occur as a result of our reduced liquidity. If we are unable to successfully negotiate a forbearance agreement, obtain a waiver of compliance or cure the borrowing base deficiency, an event of default under our credit facility would occur on November 9, 2015. In an event of default, the administrative agent may, and at the request of the majority of lenders, shall by notice to us, take either or both of the following actions: (i) immediately terminate the commitments under our credit facility, and (ii) declare the loans then outstanding under the credit facility to be immediately due and payable. Additionally, we were not in compliance with all covenants under our credit facility as of September 30, 2015. As a result of the reduction to our borrowing base and covenant deficiencies, we are unable to borrow under our credit facility. If we are unable to secure additional financing, refinance our debt, or reach a solution with our lenders, then we expect that we will not be able to pay our obligations as they become due. If the indebtedness under credit facility is accelerated, we may have to file for bankruptcy.

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To increase our liquidity to levels sufficient to satisfy our obligations and finance our capital requirements, we are currently pursuing or considering a number of actions including (i) exploring and evaluating potential sources of capital to refinance our existing debt, (ii) restructuring and sale of certain of our assets, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital and (vi) improving our cash flows from operations. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period required to meet certain obligations. Additionally, covenants contained in our debt agreements may limit our ability to pursue certain of the above strategies. The terms of our credit facility require that some or all of the proceeds from certain asset sales be used to permanently reduce outstanding debt which could substantially reduce the amount of proceeds we retain. Covenants in our credit facility also impose limitations on the amount and type of additional indebtedness we can incur, which may significantly reduce our ability to obtain liquidity through the incurrence of additional indebtedness. Furthermore, our ability to refinance our existing indebtedness on commercially reasonable terms may be materially and adversely impacted by the current conditions in the energy industry and our financial condition. If commodity prices do not significantly increase from current levels and we are unable to complete some or all of the above mentioned actions, our liquidity position will be significantly constrained in the future.

The uncertainty associated with our ability to repay our outstanding debt obligations as they become due and finance our capital requirements raises substantial doubt about our ability to continue as a going concern.

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, those amounts are not 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 are currently operating with a working capital deficit and expect to incur additional operating losses over the next twelve months, so we will have to find alternative sources of capital to meet our capital requirements. 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. 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. We suspended distributions on our common units in July 2015.

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 nine months ended September 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(1)		Total
2015
First Quarter	May 15, 2015	$	0.20	$	3,312	$	—	$	—	$	3,312
Second Quarter	N/A	$	—	$	—	$	—	$	—	$	—
Third 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

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  Third Quarter November 14, 2014 $ 0.585 $ 9,454 $ 1,290 $ 91 $ 10,835

__________

(1) In April 2015, all 155,102 General Partner Units were canceled and converted to common units. See additional discussion in Note 11 "Related Party Transactions" to our unaudited condensed consolidated financial statements in this report for additional discussion

A quarterly distribution of $0.6875 per Series A Preferred Unit, totaling $1.3 million, was due to be paid on October 15, 2015. Due to the borrowing base deficiency under our credit facility, we were prevented from paying these distributions. These distributions were accrued and included in Series A Cumulative Convertible Preferred Units in the accompanying unaudited condensed consolidated balance sheet as of September 30, 2015. If we do not pay distributions in full on any two distribution payment dates (whether consecutive payment dates or not), the per annum distribution rate will increase by an additional 2.00% per quarterly distribution not paid, up to a maximum rate per annum of 20.00% per Series A Preferred Unit on and after the day following such second distribution payment date. If all accrued distributions are paid, the distribution rate will return to 11.0%.

On July 29, 2015, we 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 $19.1 million and $26.4 million for the nine months ended September 30, 2015 and 2014, respectively. The decrease in cash provided by operating activities is a result of decreased revenues from oil, natural gas and NGL production as a result of declines in commodity prices and production volumes. The decrease is partially offset by the oilfield service acquisitions that occurred in June 2014, which increased our revenue from oilfield services. Additionally, we received cash upon settlement of our derivative contracts in the 2015 period versus paying cash to the counterparty upon settlement of our derivative contracts in the 2014 period.

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 $7.4 million and $91.0 million for the nine months ended September 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 nine months ended September 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 $(15.8) million and $63.0 million for the nine months ended September 30, 2015 and 2014, respectively. Net cash used in financing activities for the nine months ended September 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 $43.0 million on amounts outstanding under the credit facility. Additionally, net cash used in financing activity for 2015 reflects payments on our factoring payable of $9.5 million. Net cash provided by financing activities for the nine months ended September 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 $(83.3) million and $3.4 million at September 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 nine months ended September 30, 2015. Also contributing to the working deficit at September 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 September 30, 2015 and December 31, 2014 would have been $(70.4) 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 and current liquidity concerns, we have curtailed drilling activity and reduced our investment level to maintain the lower levels of operation. For the nine months ended September 30, 2015 and 2014, our maintenance capital expenditures were approximately $1.3 million and $12.8 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. However, we do not anticipate any significant growth capital expenditures in the near future.

Because our future cash flows are subject to a number of variables, including production levels and the prices we receive for our production and services, there can be no assurance that our operations and other capital resources will provide sufficient cash flow to maintain our current production levels. Our drilling activity for 2015 is limited and dependent on commodity prices. We do not currently plan to drill any wells in the fourth quarter of 2015 or first quarter of 2016. 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 commodity 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 set to mature in February 2017. 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 us 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 our ability 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 us to make distributions to our common unit holders in an amount not to exceed "available cash" (as defined in our First Amended and Restated Agreement of Limited Partnership) if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed 90%. As of September 30, 2015, we were not in compliance with one of the covenants under the credit facility.

In the second quarter of 2015, our borrowing base was lowered from $90.0 million to $57.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions and in response to the settlement of a portion of our derivative contracts prior to their contractual maturity. As of September 30, 2015, we had $49.0 million in outstanding borrowings with no available borrowing capacity. As a result of our semi-annual redetermination on October 9, 2015, our borrowing base was reduced to $24.0 million due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. The reduced borrowing base results in a $25.0 million borrowing deficiency. Any deficiency under the credit facility is required to be settled in full within 30 days or in equal installments over a 90-day period. During a deficiency, an additional 2.00% is applied to the interest rate on the outstanding balance under the credit facility, not to exceed the maximum rate as defined in the credit agreement. Our lenders also has the option to cause the liquidation of collateral in order to satisfy the deficiency. In an event of default, the administrative agent may, and at the request of the majority of lenders, declare the outstanding balance under the credit facility immediately due and payable. The Partnership is in discussions with the lenders under the credit facility and expects to enter into a forbearance arrangement soon.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.50%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At September 30, 2015 and December 31, 2014, the average annual interest rate on borrowings outstanding under the credit facility was 3.47% and 3.44%, respectively. The forbearance agreement or any waiver may postpone interest payments for a certain time frame. However, interest may continue to accrue at the default rate.

Notes Payable

MCES Notes Payable. We have 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 September 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 September 30, 2015. We had $4.6 million outstanding, of which $4.2 million was current, under the MCES notes payable as of September 30, 2015.

EFS Loan Agreement. In conjunction with the Services Acquisition, we 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 September 30, 2015 was $9.9 million.

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The note payable has a variable interest rate based on the Bank 7 Base Rate minus 2.30%, which was 5.50% at September 30, 2015, with a minimum interest rate of 5.50%. 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. We are required to maintain a reserve bank account into which $0.3 million shall be deposited quarterly, 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 their 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 and increasing to at least $3.5 million by October 1, 2015, in each case as more fully described in the loan agreement. As of September 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 September 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 wholly-owned by Mr. Kos and 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. Effective October 1, 2015, these promissory notes were canceled and the properties were transferred back to entities owned by Messrs. Kos and Tourian. See Note 11 "Related Party Transactions" and Note 16 "Subsequent Events" for additional discussion of the related party land transactions and promissory note dissolution.

MCLP Promissory Note. MCLP issued a promissory note in September 2015 for approximately $9.1 million to pay the cash portion of the contingent consideration due to the former owners of EFS and RPS in connection with the Services Acquisition. We are required to make monthly interest payments at an annual rate of 5.50% with principal and any unpaid interest due May 1, 2016. See Note 14 "Commitments and Contingencies" for additional discussion of the contingent consideration.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. In June 2015, the maturity date of the line of credit was extended to September 2015 and was lowered to a maximum of $3.0 million with the borrowing base determined based on MCES' eligible accounts receivable. Additionally, our interest rate was increased to 4.00% over the Bank of Oklahoma Financial Corporation National Prime Rate, or 8.00% at September 30, 2015. The outstanding balance was $0.8 million at September 30, 2015 and was reflected as current debt on the accompanying unaudited condensed consolidated balance sheet at September 30, 2015. The line of credit was paid in full in October 2015 and replaced with a new factoring arrangement.

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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 we receive 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 3.00% (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 unaudited condensed consolidated statement of operations. If a receivable is not collected within 90 days, the receivable is repurchased by us out of either our reserve fund or current advances. The outstanding balance of the factoring payable was $3.7 million as of September 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. The borrowing base reduction to $24.0 million results in a borrowing deficiency of $25.0 million. Any deficiency under the credit facility is required to be settled in full within 30 days or in equal installments over a 90-day period. Holders of our Series A Preferred Units are entitled to receive quarterly cash distributions at the rate of 11.00% per annum. If we do not pay distributions in full on any two distribution payment dates (whether consecutive payment dates or not), the per annum distribution rate will increase by an additional 2.00% per quarterly distribution not paid, up to a maximum rate per annum of 20.00% per Series A Preferred Unit on and after the day following such second distribution payment date. If all accrued distributions are paid, the distribution rate returns to 11.00%. There have been no other 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 our critical accounting policies and estimates.

ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk

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

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, natural gas and NGL production. Due to the volatility of commodity prices, we periodically enter into derivative contracts to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations for a portion of our oil, natural gas and NGL production. While the use of derivative contracts limits our ability to benefit from increases in the prices of oil, natural gas and NGL, it also reduces the Partnership’s potential exposure to adverse price movements. Generally, our derivative contracts apply to a small 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.

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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 September 30, 2015, our derivative contracts consisted of collars and put options, 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, we pay the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, we receive 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) we will receive for the volumes under the contract.
Put options	We periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, we are entitled to the difference between the market price and the fixed price.

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

Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
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

Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
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

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 NGL. We are generally required to settle our commodity derivatives within five days of the end of the month.

As we have 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.

In the fourth quarter of 2015, all of our open derivative contracts for the periods October 2015 through December 2015 and calendar year 2016 were monetized for approximately $1.1 million.

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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 nine months ended September 30, 2015 and 2014 (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
Cash receipts (payments) upon settlement (1)	$	2,442	$	(338	)	$	10,781	$	(3,750	)

__________

(1) Cash receipts upon settlement of derivative contracts for the nine months ended September 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.

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 us under our credit facility constitutes a default under our 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, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts. Our loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against amounts owed, if any, to such counterparty under the credit facility. As of September 30, 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 September 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 September 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 September 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.

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Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of September 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 and the Quarterly Report on Form 10-Q for the period ended September 30, 2015.

The material weaknesses we identified in 2014, 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.

Additionally, we identified a material weakness in our internal controls over financial reporting in preparing the 2015 Quarterly Report on Form 10-Q for the period ended September 30, 2015. The material weakness relates to our lack of controls needed to ensure that all material agreements, including those entered into with or on behalf of related parties, that have accounting and disclosure implications on our consolidated financial statements have been accounted for on a timely basis, or correctly at all. The material weakness was identified by our independent registered public accounting firm.

Notwithstanding the existence of the material weaknesses, management has concluded that the financial statements included in this report present fairly, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with GAAP.

Management's Remediation Activities

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

As of September 30, 2015, we have not yet been able to remediate these material weaknesses. While we have hired additional accounting personnel, we expect that we will need to utilize outside consulting firms with technical accounting and financial reporting experience. 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 Partnership’s internal control over financial reporting during the quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, the Partnership’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 quarters ended March 31, 2015 and June 30, 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, NSEC and New Dominion (collectively, “plaintiffs”) filed a lawsuit against us, 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 us. The plaintiffs also allege that we have been unjustly enriched and that the properties acquired from them by us 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. The plaintiffs also 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 we are wrongfully refusing to remove the restrictive legends on common units issued by us to the plaintiffs in private transactions in exchange for the oil and natural gas working interests described above.

Hearings on certain motions to dismiss filed by the defendants were held on August 5, 2015 and September 11, 2015. On September 15, 2015, the parties agreed to stay this proceeding pending settlement discussions. 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. A reserve of $1.2 million on the outstanding net receivable was recorded and is reflected in the related party receivable, net balance at September 30, 2015.

In addition to the proceeding described above, 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 total amount of 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. In the lawsuit, we seek a temporary and permanent injunction and declaratory action and asserts breach of contract, negligence, gross negligence, willful misconduct and fraud against the various defendants. On September 15, 2015, the parties agreed to stay this proceeding pending settlement discussions.

The Partnership and plaintiffs have engaged in settlement discussions; however, a settlement has not been reached. Under a settlement agreement, it is possible that the Partnership could recognize a gain or loss on the ultimate transaction. Information necessary to determine such a gain or loss is not currently available. If a settlement is not reached, the Partnership plans to continue to vigorously pursue its claims. The Partnership believes that plaintiffs owe it the amounts it has recorded, that plaintiffs have the ability to pay these amounts, and that plaintiffs’ claims against the Partnership are without merit. However, as a result of the ongoing litigation with New Dominion, a reserve of $1.2 million on the outstanding net receivable was recorded and is reflected in the related party receivable, net balance at September 30, 2015.

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

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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 us 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.

Fair Labor Standards Act Litigation. EFS and RPS are involved in two separate, yet similar lawsuits in which the plaintiff claims he and other similarly situated flow hands or “flow backs” were misclassified as independent contractors, as opposed to employees with overtime entitlement, in violation of the Fair Labor Standards Act (“FLSA”) and in violation of various state laws. Both cases are brought by the same individual plaintiff and are against EFS and RPS, respectively. The same law firm represents the plaintiffs in both cases. We have not been added as a named party in either of these cases, but it could potentially be added in the future.

Specifically, these matters are:

•Jeremy Saenz, on Behalf of Himself and All Others Similarly Situated v. Rod’s Production Services, LLC: This is a purported collective action and class action filed on June 2, 2015 in the United States District Court for the District of New Mexico. The plaintiff claims that RPS misclassified him as an independent contractor under the FLSA and New Mexico state law. The plaintiff also filed a motion to amend to add state law claims under Pennsylvania and Ohio wage laws. The plaintiff seeks unpaid overtime for the time he worked as a misclassified independent contractor. The court conditionally certified the collective action under the FLSA and the opt-in period closed on July 15, 2015. The parties dispute how many proper opt-ins have been filed, but the class will range between 64 and 80 opt-in plaintiffs, including the named plaintiff. The parties are beginning discovery. The parties have a scheduling order from the court. Discovery cutoff is May 16, 2016 and trial is scheduled for February 2017.

•Jeremy Saenz, on Behalf of Himself and All Others Similarly Situated v. Erick Flowback Services, LLC: This is a purported collective action and class action filed on June 10, 2015 in the United States District Court for the Western District of Oklahoma. The plaintiff claims that EFS misclassified him as an independent contractor under the FLSA, and Ohio and Pennsylvania state laws. The plaintiff seeks unpaid overtime for the time he worked as a misclassified independent contractor. The court conditionally certified the collective action and the opt-in period closed on August 11, 2015. The parties dispute the number of proper opt-in plaintiffs, but the class will be between 76 and 100 plaintiffs, including the named plaintiff. The parties had a scheduling conference on September 16, 2015. Currently, the parties are briefing the scope of discovery. The court has not yet entered a scheduling order.

We recorded a reserve for the above Fair Labor Standards Act Litigation of $1.5 million, reflective of the facts and circumstances as currently known. The actual loss may differ from the established reserve. On October 28, 2015, the parties entered into an Agreement to Stay Proceedings that stays the current litigation and provides the parties with a 60-day mediation period, unless extended by the parties.

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On October 21, 2015, a class action complaint was filed in the Supreme Court of the State of New York against us, certain current and former directors of our general partner and certain investment banking firms in the case styled Enrico Vaccaro vs. New Source Energy Partners L.P., Kristian B. Kos, Terry L. Toole, Dikran Tourian, Richard D. Finley, V. Bruce Thompson, John A. Raber, Stifel, Nicholas & Company, Inc. Robert W. Baird & Co. Inc., Janney Montgomery Scott LLC, Oppenheimer & Co. Inc., and Wunderlich Securities, Inc.  The complaint asserts a state securities class action on behalf of a putative class consisting of persons or entities who purchased or otherwise acquired Series A Preferred Units pursuant to the related prospectus and prospectus supplement, seeking to recover damages allegedly caused by the defendants’ violations of the federal securities laws under Sections 11, 12(a)(2) and 15 of the Securities Act.  The complaint alleges that the defendants made materially false and misleading statements regarding our business and operations because such statements failed to properly reflect the impact of certain actions by our contract operator on the Partnership’s financial condition.  We and the other defendants associated with us intend to defend this lawsuit vigorously. 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 plaintiff’s claims and the defendants’ defenses are fully disclosed and analyzed. We have not established any reserves relating to this action.

We 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, we believe the reasonably possible losses of such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our 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.

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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 Reports on Form 10-Q for the quarters ended March 31, 2015 and June 30, 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 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 September 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 $57.0 million based on our estimated oil, natural gas and NGL reserves using commodity pricing reflective of the current market conditions and with consideration of the settlement of a portion of our derivative contracts prior to their contractual maturity. As of September 30, 2015, the Partnership had $49.0 million in outstanding borrowings with no available borrowing capacity. As a result of our semi-annual redetermination on October 9, 2015, our borrowing base was reduced to $24.0 million due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. The reduced borrowing base results in a borrowing deficiency of $25.0 million. Our credit facility requires any deficiency to be settled in full within 30 days or in equal installments over a 90-day period. Our lenders also have the option to cause the liquidation of collateral in order to satisfy the deficiency. In an event of default, the administrative agent may, and at the request of the majority of lenders, declare the outstanding balance under the credit facility immediately due and payable. The Partnership is in discussions with the lenders under the credit facility and expects to enter into a forbearance arrangement soon.

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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 $61.5 million and $228.6 million for the three and nine months ended September 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 and may continue to suspend distributions on our common units for additional quarters. Due to the borrowing base deficiency under our credit facility, as discussed in Note 3 "Debt" to our unaudited condensed consolidated financial statements in this report, we were prevented from paying distributions on our Series A Preferred Units. We 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.

Due to our substantial liquidity concerns, we may be unable to continue as a going concern.

Recent declines in commodity prices, a decline in operating revenues and cash flows from our oilfield services business and the withholding of revenue from our working interest by our contract operator have caused a reduction in our available liquidity and we may not have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to cure our borrowing base deficiency. As a result of our semi-annual redetermination of our credit facility on October 9, 2015, our borrowing base was reduced to $24.0 million due to continued declines in oil, natural gas and NGL prices and the resulting impact on our reserves. The reduced borrowing base results in a borrowing deficiency of $25.0 million. Our credit facility requires any deficiency to be settled within 30 days of our receipt of notice of the deficiency or in equal installments over a 90-day period. We do not currently have sufficient cash resources to repay or additional collateral to cure the borrowing base deficiency. Our lenders also

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have the option to cause the liquidation of collateral in order to satisfy the deficiency. If we are unable to successfully negotiate a forbearance agreement, obtain a waiver of compliance or cure the borrowing base deficiency, an event of default under our credit facility would occur on November 9, 2015. In addition, if we have a going concern qualification in our audited consolidated financial statements for the year ended December 31, 2015, then we will be in default under our credit facility at the time we furnish our audited consolidated financial statements to our lenders. We are required to furnish our audited consolidated financial statements to our lenders within 90 days after the end of our fiscal year on December 31, 2015. In an event of default, the administrative agent may, and at the request of the majority of lenders, shall by notice to us, take either or both of the following actions: (i) immediately terminate the commitments under our credit facility, and (ii) declare the notes and the loans then outstanding under the credit facility to be immediately due and payable. While we will attempt to take appropriate mitigating actions to cure our borrowing base deficiency and any other potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing our borrowing base deficiency and any other potential defaults in our existing and future debt agreements will be sufficient. If the indebtedness under our revolving credit facility or any of our other indebtedness is accelerated, we may have to file for bankruptcy. The uncertainty associated with our ability to cure our borrowing base deficiency and repay our other outstanding debt obligations as they become due raises substantial doubt about our ability to continue as a going concern.

Due to reduced commodity prices, a decline in operating revenues and cash flows from our oilfield services business and the withholding of revenue from our working interest by our contract operator, coupled with our borrowing base deficiency on our revolving credit facility, we may be unable to maintain adequate liquidity and our ability to cure our borrowing base deficiency could be adversely affected.

Recent declines in commodity prices, a decline in operating revenues and cash flows from our oilfield services business and the withholding of revenue from our working interest by our contract operator have caused a reduction in our available liquidity and we may not have the ability to generate sufficient cash flows from operations and, therefore, sufficient liquidity to cure our borrowing base deficiency or meet our anticipated working capital and other liquidity needs. We are currently evaluating strategic alternatives to address our liquidity issues and borrowing base deficiency. We cannot assure you that any of these efforts will be successful or will result in cost reductions or additional cash flows or the timing of any such cost reductions or additional cash flows. In order to increase our liquidity to levels sufficient to cure our borrowing base deficiency and meet our commitments, we are currently pursuing or considering a number of actions including (i) exploring and evaluating potential sources of capital to refinance our existing debt, (ii) restructuring and sale of certain of our assets, (iii) minimizing our capital expenditures, (iv) obtaining waivers or amendments from our lenders, (v) effectively managing our working capital and (vi) improving our cash flows from operations. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transactions can be consummated within the period needed to cure our borrowing base deficiency and meet certain other obligations.  We cannot assure you that any refinancing or debt or equity restructuring would be possible or that additional equity or debt financing could be obtained on acceptable terms, if at all. Furthermore, we cannot assure you that any of our strategies will yield sufficient funds to cure our borrowing base deficiency and meet our working capital or other liquidity needs, and any such alternative measures may be unsuccessful or may not permit us to cure our borrowing base deficiency, which could cause us to default on our revolving credit facility and other debt obligations.

The borrowing base under our revolving credit facility was recently reduced by our lenders, and we are required to repay a portion of the borrowings under our revolving credit facility. If we are unable to cure the borrowing base deficiency and our indebtedness is accelerated, we may have to file for bankruptcy.

Our revolving credit facility limits the amounts we can borrow up to the lesser of the committed amount and a borrowing base amount, which is subject to redeterminations by the lenders semi-annually each April and October. Our borrowing base under our revolving credit facility was subject to its semi-annual redetermination on October 9, 2015, and was decreased from $57.0 million to $24.0 million.  Because our revolving credit facility is fully drawn, the decrease in our borrowing base as a result of the redetermination resulted in a deficiency of approximately $25.0 million which must be repaid within 30 days of our receipt of notice of the deficiency or in equal installments over a 90-day period. We do not currently have sufficient cash resources to repay or additional collateral to cure the borrowing base deficiency. We are currently engaged in discussions with the lenders under our credit regarding a waiver or forbearance with respect to any event of default that may occur as a result of our reduced liquidity. If we are unable to successfully negotiate a forbearance agreement, obtain a waiver of compliance or cure the borrowing base deficiency, an event of default under our credit facility would occur on November 9, 2015. In addition, if we have a going concern qualification in our audited consolidated financial statements for the year ended December 31, 2015, then we will be in default under our credit facility at the time we furnish our audited consolidated financial statements to our lenders. We are required to furnish our audited consolidated financial statements to our lenders within 90 days after the end of our fiscal year on December 31, 2015. In an event of default, the administrative agent may, and at the request of the majority of lenders, shall by notice to us,

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take either or both of the following actions: (i) immediately terminate the commitments under our credit facility, and (ii) declare the notes and the loans then outstanding under the credit facility to be immediately due and payable. If the indebtedness under our revolving credit facility or any of our other indebtedness is accelerated, we may have to file for bankruptcy.

Our substantial indebtedness, liquidity issues and the potential for restructuring transactions may impact our business, financial condition and operations.

Due to our substantial indebtedness, liquidity issues and the potential for restructuring, there is risk that, among other things:

• third parties’ confidence in our ability to explore and produce oil and natural gas could erode, which could impact our ability to execute on our business strategy;

• it may become more difficult to retain, attract or replace key employees;

• employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and

• our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.

The occurrence of certain of these events has already negatively affected our business and may have a material adverse effect on our business, results of operations and financial condition.

Our common units were delisted from the NYSE as a result of non-compliance with a listing standard for continued listing of our common units and we are now quoted only in over-the-counter markets. Our delisting from the NYSE carries substantial risks and could continue to negatively impact our unit price, volatility, liquidity and ability to raise capital.

On September 9, 2015, we were notified by the NYSE that we were not in compliance with the continued listing standards set forth in Sections 802.01B and 802.01C of the NYSE Listed Company Manual because we failed to maintain an average global market capitalization over a consecutive 30 trading-day period of at least $15.0 million for our common units and the average closing price of our common units was less than $1.00 over a consecutive 30 trading-day period. On October 5, 2015, the NYSE filed a Form 25 with the SEC to delist our common units. Since then, our common units have been quoted on the OTC Market Group under the ticker symbol “NSLP.”

Securities traded in over-the-counter markets generally have substantially less volume and liquidity than securities traded on a national securities exchange such as the NYSE as a result of various factors, including the reduced number of investors that will consider investing in the securities, fewer market makers in the securities, and a reduction in securities analyst and news media coverage. As a result, holders of our common units may have difficulty selling their units and our unit price could experience additional downward pressure. Furthermore, the price of our common units could be subject to greater volatility and could be more likely to be affected by market conditions and fluctuations, changes in our operating results, market perception of us and our business, and announcements by us or other parties with an interest in our business. The lack of liquidity in our common units may also make it difficult for us to issue additional securities for financing or other purposes, or to otherwise arrange for any financing we may need in the future.

Delisting may have other negative results, including the potential loss of confidence by contractors and employees, the loss of institutional investor interest in us and fewer business development opportunities from strategic partners. The delisting of our common units from the NYSE could further depress our unit price, substantially limit the liquidity of our common units and materially affect our ability to raise capital.

ITEM 3. Defaults Upon Senior Securities

The Partnership is subject to certain financial covenants under its credit facility, one of which stipulates that the Partnership maintain a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0.  Due to the $25.0 million borrowing base deficiency resulting from the October 9, 2015 redetermination, we are in violation of this covenant. See Note 3 "Debt" to our unaudited condensed consolidated financial statements in this report for additional discussion of our credit facility.

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A quarterly distribution of $0.6875 per Series A Preferred Unit, totaling $1.3 million, was due to be paid on October 15, 2015.  Due to the borrowing base deficiency under our credit facility, as discussed in Note 3 "Debt" to our unaudited condensed consolidated financial statements in this report, we were prevented from paying these distributions. These distributions were accrued and included in accounts payable and accrued liabilities in the accompanying unaudited condensed consolidated balance sheet as of September 30, 2015.

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 November 9, 2015.

New Source Energy Partners L.P.
By: New Source Energy GP, LLC, its general partner
/s/ Paula Maxwell
By:	Paula Maxwell
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
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 Paula Maxwell, 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 Paula Maxwell, 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					*
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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