New Source Energy Partners (NSLP) 10-Q 2013 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

(MARK ONE)

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

For the quarterly period ended June 30, 2013

or

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

For the transition period from ____________ to ____________.

Commission File Number: 001-35809

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

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

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

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

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

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

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

As of August 13, 2013, the registrant had 6,773,500 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.

1

NEW SOURCE ENERGY PARTNERS, L.P.

Form 10-Q

Quarter Ended June 30, 2013

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
	Item 1.	Financial Statements	6
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24
	Item 4.	Controls and Procedures	25
PART II – OTHER INFORMATION			25
	Item 1.	Legal Proceedings	25
	Item 1A.	Risk Factors	26
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	26
	Item 6.	Exhibits	26
SIGNATURES			29

2

NAMES OF ENTITIES

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

● The “Partnership,” “we,” “our,” “us” or like terms refer collectively to New Source Energy Partners L.P. and its subsidiaries;

● “our general partner” refers to New Source Energy GP, LLC, our general partner;

● “New Source Energy” refers to New Source Energy Corporation;

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

● “Scintilla” refers to Scintilla, LLC, the entity from which New Source Energy acquired substantially all of its assets in August 2011;

● “New Source Group” collectively refers to New Source Energy, New Dominion and Scintilla; however, when used in the context of the development agreement described in this Quarterly Report on Form 10-Q, the New Source Group refers to the parties (other than us) party thereto; and

● “our management,” “our employees,” or similar terms refer to the management and personnel of New Source Energy who perform managerial and administrative services on behalf of us and our general partner under an omnibus agreement among us, our general partner and New Source Energy.

3

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

The information discussed in this Quarterly Report on Form 10-Q includes “forward-looking statements.” These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others, the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2012 and in this report, as well as those factors summarized below:

● our ability to replace oil and natural gas reserves;

● declines or volatility in the prices we receive for our oil, natural gas and NGLs;

● our financial position;

● our ability to generate sufficient cash flow and liquidity from operations, borrowings or other sources to enable us to pay our obligations and maintain our non-operated acreage positions;

● future capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

● there are significant interlocking relationships between us and the New Source Group, and there can be no assurance that these interlocking relationships may not result in conflicts of interest and other risks to decision-making actions by our officers and directors in the future;

● our ability to continue our working relationship with the New Source Group;

● general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business;

● economic downturns may adversely affect consumption of oil and natural gas by businesses and consumers;

● the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs;

● uncertainties associated with estimates of proved oil and natural gas reserves and various assumptions underlying such estimates;

● our ability to successfully acquire additional working interests through the efforts of the New Source Group in forced pooling processes;

● the requirement applicable to us as a public company to implement and assess periodically the effectiveness of our internal control over financial reporting and the substantial costs associated with doing so;

● the impact of environmental, health and safety, and other governmental regulations and of current or pending legislation;

● environmental risks;

● geographical concentration of our operations;

● constraints imposed on our business and operations by our revolving credit facility and our ability to generate sufficient cash flows to repay our debt obligations;

● availability of borrowings under our revolving credit facility;

● drilling and operating risks;

● exploration and development risks;

4

● competition in the oil and natural gas industry;

● increases in the cost of drilling, completion and gas gathering or other costs of production and operations;

● the inability of the New Source Group to successfully drill wells on our properties that produce oil or natural gas in commercially viable quantities;

● failure to meet the proposed drilling schedule on our properties;

● adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

● drilling operations and adverse weather and environmental conditions;

● limited control over non-operated properties;

● reliance on a limited number of customers;

● management’s ability to execute our plans to meet our goals;

● our ability to retain key members of our management and key technical employees;

● conflicts of interest with regard to our directors and executive officers;

● access to adequate gathering systems and pipeline take-away capacity to execute our drilling program;

● marketing and transportation constraints in the Hunton Formation in east-central Oklahoma;

● our ability to sell the oil and natural gas we produce at market prices;

● costs associated with perfecting title for mineral rights in some of our properties;

● title defects to our properties and inability to retain our leases;

● federal, state, and tribal regulations and laws;

● our current level of indebtedness and the effect of any increase in our level of indebtedness;

● risks relating to potential acquisitions and the integration of significant acquisitions;

● volatility of oil, natural gas and NGL prices and the effect that lower prices may have on our net income and unitholders’ equity;

● a decline in oil or natural gas production or oil, natural gas or NGL prices and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;

● the effect of seasonal factors;

● lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oilfield services;

● further sales or issuances of common units;

● our limited trading history;

● costs of purchasing electricity and disposing of saltwater;

● continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and

● other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing.

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in “Item 1A.  Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Quarterly Report on Form 10-Q and speak only as of the date of this report. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

5

PART I – FINANCIAL INFORMATION

Item 1.        Financial Statements

New Source Energy Partners L.P.

Condensed Balance Sheets

(unaudited, in thousands, except unit amounts)

	June 30,			December 31,
	2013			2012
ASSETS
Current assets:
Cash	$	865		$	-
Oil and natural gas sales receivable		7,067			5,621
Oil and natural gas sales receivable-related parties		150			42
Derivative assets		1,067			25
Total current assets		9,149			5,688
Property and equipment:
Oil and natural gas properties, at cost, using full cost method:
Proved oil and natural gas properties		245,016			202,795
Accumulated depreciation, depletion, and amortization		(119,144	)		(112,372	)
Total property and equipment, net		125,872			90,423
Prepaid drilling and completion costs		967			1,000
Loan fees, net		1,578			1,508
Deferred offering costs		-			1,315
Derivative assets		1,393			-
Total assets	$	138,959		$	99,934
LIABILITIES, PARENT NET INVESTMENT AND PARTNERS' CAPITAL:
Current liabilities:
Accounts payable	$	6		$	-
Accounts payable-related parties		3,514			1,564
Accrued liabilities		129			259
Accrued income taxes		-			103
Derivative obligations		58			47
Total current liabilities		3,707			1,973
Long-term related party payables		358			345
Credit facility		48,000			68,000
Derivative obligations		-			107
Asset retirement obligation		2,950			1,510
Deferred tax liability		-			12,024
Total liabilities		55,015			83,959
Commitments and contingencies (See Note 10)
Parent net investment		-			15,975
Partners' capital:
Common units (6,773,500 units outstanding at June 30, 2013)		104,132			-
Subordinated units (2,205,000 units outstanding at June 30, 2013)		(18,903	)		-
General partner's capital (155,102 units outstanding at June 30, 2013)		(1,285	)		-
Total partners' capital		83,944			15,975
Total liabilities, parent net investment and partners' capital	$	138,959		$	99,934

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

6

New Source Energy Partners L.P.

Condensed Statements of Operations

(unaudited, in thousands, except per unit amounts)

	Three months ended June 30,						Six months ended June 30,
	2013			2012			2013			2012
REVENUES
Oil sales		1,636			1,522			2,834			2,981
Natural gas sales		2,642			1,159			4,449			2,569
Natural gas liquids sales		6,371			5,475			12,726			12,636
Total revenues	$	10,649		$	8,156		$	20,009		$	18,186
OPERATING COSTS AND EXPENSES
Oil and natural gas production expenses		2,827			1,914			5,274			3,656
Oil and natural gas production taxes		486			306			1,439			651
General and administrative		1,246			4,126			10,100			8,452
Depreciation, depletion and amortization		3,577			3,700			6,772			7,643
Accretion expense		57			29			86			57
Total operating costs and expenses		8,193			10,075			23,671			20,459
Operating income (loss)		2,456			(1,919	)		(3,662	)		(2,273	)
OTHER INCOME (EXPENSE)
Interest expense		(487	)		(786	)		(2,566	)		(1,598	)
Realized gain (loss) from derivatives, net		(120	)		1,031			(341	)		1,207
Unrealized gain from derivatives, net		6,302			6,466			1,197			7,205
Income before income taxes		8,151			4,792			(5,372	)		4,541
Income tax benefit (expense)		-			(1,871	)		12,126			(1,728	)
Net income	$	8,151		$	2,921		$	6,754		$	2,813
ALLOCATION OF NET INCOME FOR THREE AND SIX MONTHSENDED JUNE 30, 2013:
Net income							$	6,754
Net income prior to purchase of properties from New Source Energyon February 13, 2013							$	5,303
Net income subsequent to purchase of properties from New Source Energyon February 13, 2013							$	1,451
Net income allocable to general partner from February 13, 2013to June 30, 2013							$	5
Net income allocable to subordinated units from February 13, 2013to June 30, 2013							$	49
Net income allocable to common units from February 13, 2013to June 30, 2013							$	1,397
Net income per common unit from February 13, 2013 to June 30, 2013							$	0.22
Net income allocable to general partner for the three monthsended June 30, 2013	$	138
Net income allocable to subordinated units for the three monthsended June 30, 2013	$	1,968
Net income allocable to common units for the three monthsended June 30, 2013	$	6,045
Net income per common unit	$	0.89

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

7

New Source Energy Partners L.P.

Statement of Partners' Capital

For the six months ended June 30, 2013

(unaudited, dollars in thousands)

	Parent Net			Common Units					Subordinated Units					General Partner Units					Total Partners'
	Investment			Units		Captial			Units		Capital			Units		Capital			Capital
Balance, December 31, 2012	$	15,975			-	$	-			-	$	-			-	$	-		$	-
Net income attributable to the period from January 1, 2013 to February 12, 2013		5,303			-		-			-		-			-		-			-
Allocated equity-based compensation of parent		388			-		-			-		-			-		-			-
Distribution to parent attributable to period from January 1, 2013 to February 12, 2013		(2,495	)		-		-			-		-			-		-			-
Subordinated note to parent at closing		(25,000	)		-		-			-		-			-		-			-
Cash paid to parent at closing		(15,800	)		-		-			-		-			-		-			-
Distribution of accounts receivable to parent		(7,014	)		-		-			-		-			-		-			-
Accounts payable assumed by parent		1,742			-		-			-		-			-		-			-
Purchase of oil and natural gas properties from New Source Energy in exchange for units		26,901			777,500		(7,306	)		2,205,000		(18,347	)		150,000		(1,248	)		(26,901	)
Proceeds from equity offering, net of offering costs		-			4,250,000		76,565			-		-			-		-			76,565
Issuance to general partner from overallotment exercised		-			-		-			-		-			5,102		-			-
Equity-based compensation		-			367,500		7,350			-		-					-			7,350
Units issued in exchange for oil and natural gas properties		-			1,378,500		27,983			-		-			-		-			27,983
Distribution to unit holders		-			-		(1,857	)		-		(605	)		-		(42	)		(2,504	)
Net income attributable to the period from February 13, 2013 to June 30, 2013		-			-		1,397			-		49			-		5			1,451
Balance, June 30, 2013	$	-			6,773,500	$	104,132			2,205,000	$	(18,903	)		155,102	$	(1,285	)	$	83,944

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

8

New Source Energy Partners L.P. 

Condensed Statements of Cash Flows 

(unaudited, in thousands)

	Six months ended June 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	6,754		$	2,813
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		6,772			7,643
Write off of loan fees due to debt refinancing		1,436			-
Equity-based compensation		7,738			6,297
Deferred income tax expense (benefit)		(12,023	)		1,501
Amortization of loan fees		240			303
Accretion expense		86			57
Unrealized gain on derivatives, net		(1,197	)		(7,205	)
Payments for derivative option premiums		(1,334	)		-
Changes in operating assets and liabilities:
Oil and natural gas sales receivable		(8,437	)		1,779
Accounts payable		2,924			(789	)
Accrued liabilities		(130	)		(139	)
Income taxes payable		(103	)		55
Net cash provided by operating activities		2,726			12,315
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for oil and natural gas properties and equipment		(12,195	)		(6,468	)
Net cash used in investing activities		(12,195	)		(6,468	)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on long-term debt		(95,000	)		(1,000	)
Payments for deferred loan costs		(1,747	)		(29	)
Proceeds from sales of common units, net of offering costs		77,880			-
Proceeds from borrowings on long-term debt		50,000			1,000
Distribution to unitholders		(2,504	)		-
Distribution to parent		(18,295	)		(5,818	)
Net cash provided by (used in) financing activities		10,334			(5,847	)
Net change in cash and cash equivalents		865			-
Cash and cash equivalents, beginning of period		-			-
Cash and cash equivalents, end of period	$	865		$	-
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest expense	$	1,020		$	1,434
NON-CASH INVESTING AND FINANCING ACTIVITIES
Capitalized asset retirement obligation	$	1,354		$	22
Increase (decrease) in accrued capital expenditures		786			(841	)
Accounts receivable distributed to parent		(7,014	)		-
Accounts payable assumed by parent		(1,742	)		-
Subordinated note given to parent in exchange for oil and gas properties		25,000			-
Purchase of oil and natural gas properties in exchange for units		(27,983	)		-

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

9

 1.  Summary of Significant Accounting Policies

Organization

New Source Energy Partners L.P. (the “Partnership”) is a Delaware limited partnership formed in October 2012 by New Source Energy Corporation (“New Source Energy”) to own and acquire oil and natural gas properties in the United States.

On February 13, 2013, the Partnership completed its initial public offering (the “Offering”) of 4,000,000 common units representing limited partner interests in the Partnership at a price to the public of $20.00 per common unit. The Partnership received net proceeds of approximately $74.4 million from the Offering, after deducting underwriting discounts. The Partnership made a cash distribution of $15.8 million to New Source Energy as consideration (together with its issuance to New Source Energy of approximately 50% of New Source Energy, GP, LLC, which owns all of the Partnership general partner units, 777,500 common units, 2,205,000 subordinated units and a $25.0 million note payable) for the contribution by New Source Energy of certain oil and gas properties (the “IPO Properties”) and certain commodity derivative contracts.  Additionally, the Partnership assumed approximately $70.0 million of New Source Energy’s indebtedness previously secured by the IPO Properties, and used a portion of the net proceeds from the Offering to repay in full such assumed debt at the closing of the Offering. The Partnership also borrowed $15.0 million under a new revolving credit facility on February 13, 2013.  On March 12, 2013, the Partnership received net proceeds of $4.7 million from the partial exercise, in the amount of 250,000 common units, of the underwriters’ overallotment option.

The IPO Properties consist of interests in wells producing oil, natural gas, and natural gas liquids from the Misener-Hunton (the “Hunton”) formation in East-Central Oklahoma. The IPO Properties represent New Source’s working interest in certain Hunton formation producing wells located in Pottawatomie, Seminole and Okfuskee Counties, Oklahoma (“Golden Lane Area”), which equates to approximately a 38% weighted average working interest in the Golden Lane Area.

On March 29, 2013, the Partnership completed an acquisition, with an effective date of March 1, 2013, of certain oil and gas properties located in Oklahoma (the “March Acquired Properties”) from New Source Energy, Scintilla, and W.K. Chernicky, LLC, an Oklahoma limited liability company. As consideration for the March Acquired Properties, the Partnership issued an aggregate of 1,378,500 common units representing limited partner interests to the sellers. The March Acquired Properties are located in the Golden Lane Field, where the IPO Properties are located, and in the Luther Field, which is adjacent to the Golden Lane Field. 

Basis of Presentation

The accompanying unaudited condensed financial statements present the financial position of the Partnership at June 30, 2013 and December 31, 2012 and the Partnership’s results of operations and cash flows for the six months ended June 30, 2013 and 2012. These condensed financial statements include all adjustments, consisting of normal and recurring adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and the results of operations for the indicated interim periods in accordance with accounting principles generally accepted in the United States of America, or “GAAP,” for interim financial reporting.  Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted.  Therefore, these unaudited condensed financial statements should be read along with the Partnership’s financial statements and the financial statements of the IPO Properties for the year ended December 31, 2012 included in the Partnership’s Form 10-K (File No. 001-35809) for an expanded discussion of the Partnership’s financial disclosures and accounting policies.  The results of operations for the six months ended June 30, 2013 are not necessarily indicative of the results to be expected for the full year ending December 31, 2013.

Nature of Operations and Basis of Presentation

The acquisition of the IPO Properties discussed above was a transaction between businesses under common control. The accounts relating to the IPO Properties have been reflected retroactively in the Partnership’s financial statements at carryover basis. Therefore, for periods prior to February 13, 2013, the accompanying financial statements may not be indicative of the Partnership’s future performance and may not reflect what its financial position, results of operations, and cash flows would have been had it been operated as an independent company during the periods presented. Prior to February 13, 2013, New Source Energy performed certain corporate functions on behalf of the IPO Properties, and the financial statements reflect an allocation of the costs New Source Energy incurred. These functions included executive management, information technology, tax, insurance, accounting, legal and treasury services. The costs of such services were allocated based on the most relevant allocation method to the service provided, primarily based on relative book value of assets, among other factors. Management believes such allocations are reasonable; however, they may not be indicative of the actual expense that would have been incurred had the Partnership been operated as an independent company for all of the periods presented. The charges for these functions are included primarily in general and administrative expenses.

10

Use of Estimates in the Preparation of Financial Statements

Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves. Other significant estimates include, but are not limited to, the valuation of commodity derivatives and the Partnership’s common units issued in a business combination and as compensation for services, the allocation of general and administrative expenses, and asset retirement obligations.

Oil and Natural Gas Properties

The Partnership utilizes the full cost method of accounting for oil and natural gas properties whereby productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. All capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves. Under the full cost method, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the ceiling limitation). In arriving at estimated after-tax future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. Reserve estimates used in determining estimated after-tax future net revenues have been prepared by an independent petroleum engineer. Future net revenues were computed based on reserves using prices calculated as the unweighted arithmetical average oil and natural gas prices on the first day of each month within the latest twelve-month period. Subsequent to February 13, 2013, the ceiling limitation computation is determined without regard to income taxes due to the Partnership being a non-income tax paying entity. There were no full cost ceiling write-downs recorded in the six months ended June 30, 2013 or 2012.

Earnings per Unit

Basic and diluted earnings per unit is determined by dividing net income for the period by the weighted average number of units outstanding. Basic and diluted earnings per unit for the period from February 13, 2013 through June 30, 2013 were computed using the following components:

	Common Units		Subordinated Units		General Partner
Numerator
Net income (in thousands)	$	1,397	$	49	$	5
Denominator:
Weighted average units outstanding	$	6,285,065	$	2,205,000	$	154,104
Basic and diluted income per unit	$	0.22	$	0.02	$	0.03

11

Basic and diluted earnings per unit for the three months ended June 30, 2013 were computed using the following components:

	Common Units		Subordinated Units		General Partner
Numerator
Net income (in thousands)	$	6,045	$	1,968	$	138
Denominator:
Weighted average units outstanding		6,773,500		2,205,000		155,102
Basic and diluted income per unit	$	0.89	$	0.89	$	0.89

2.  Related Party Transactions

The Partnership has a working relationship with New Dominion, LLC (“New Dominion”), an exploration and production operator based in Tulsa, Oklahoma wholly owned by the Chairman of the general partner’s board of directors. Pursuant to the Partnership’s Development Agreement, New Dominion is currently contracted to operate the Partnership’s existing wells in the Hunton formation in east-central Oklahoma. New Dominion has historically performed this service for New Source Energy. As a result, all pre-Offering accounts payable related to the Partnership’s properties are presented as accounts payable – related party in the accompanying balance sheets.

New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated is approximately $0.4 million as of June 30, 2013, of which $0.1million is reflected as a current liability and $0.3 million is reflected as a long-term liability. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.

3.  Credit Agreement

On February 13, 2013, in connection with the closing of the Offering, the Partnership entered into a Credit Agreement (the “Credit Agreement”) by and among the Partnership, as borrower, Bank of Montreal, as administrative agent for the lenders party thereto (the “Administrative Agent”), and the other lenders party thereto.

The Credit Agreement is a four-year, $150 million senior secured revolving credit facility with a current borrowing base of $75 million. The borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to the estimated oil and gas reserves of the Partnership and its subsidiaries, which will take into account the prevailing oil and gas prices at such time, as adjusted for the impact of commodity derivative contracts. The Credit Agreement is available for working capital for exploration and production, to provide funds in connection with the Partnership’s acquisition of oil and gas properties contributed upon the closing of the Offering, to refinance certain indebtedness of New Source Energy and for general corporate purposes.

On February 28, 2013, the Partnership entered into a First Amendment (the “First Amendment”) to its Credit Agreement.  The First Amendment (i) added a lender under the Credit Agreement, (ii) increased the Partnership’s borrowing base under the Credit Agreement from $30 million to $60 million, (iii) increased the lenders’ aggregate commitment under the Credit Agreement from $60 million to $150 million and (iv) removed references and provisions related to the $25.0 million subordinated promissory note (the “Subordinated Note”) issued by the Partnership to New Source Energy in connection with the Partnership’s initial public offering. As a condition precedent to effectiveness of the First Amendment, the Partnership repaid the Subordinated Note in full.

On June 25, 2013, the Partnership entered into a Second Amendment (the “Second Amendment”) to its Credit Agreement. The Second Amendment (i) added two lenders under the Credit Agreement, and (ii) increased the Partnership’s borrowing base under the Credit Agreement from $60 million to $75 million.

Borrowings under the Credit Agreement bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) the Administrative Agent’s prime rate or (c) 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 will be subject to a commitment fee of 0.50% per annum. Accrued interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans, at shorter intervals. The Credit Agreement matures on February 13, 2017 and the variable rate was approximately 3.29% per annum at June 30, 2013. As of June 30, 2013, the Partnership had $48 million outstanding under the Credit Agreement and, as a result, had $27 million of available borrowing capacity. The Partnership was in compliance with all covenants of the Credit Agreement as of June 30, 2013.

12

4.  Fair Value Measurements

Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. As defined in ASC 820-10, fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Management considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that management values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as oil swaps.

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). Management’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as natural gas liquids (“NGL”) swaps, natural gas swaps for those derivatives that are indexed to local and non-observable indices, and oil, NGL and natural gas collars. Although management utilizes third party broker quotes to assess the reasonableness of our prices and valuation techniques, management does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

The Partnership’s commodity derivative contracts are accounted for at fair value.  The fair values of derivative instruments are based on a third-party pricing model which utilizes inputs that include (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures.  The estimates of fair value are compared to the values provided by the counterparty for reasonableness.  Derivative instruments are subject to the risk that counterparties will be unable to meet their obligations.  Such non-performance risk is considered in the valuation of the Partnership’s derivative instruments but to date has not had a material impact on estimates of fair values.  Significant changes in the quoted forward prices for commodities and changes in market volatility generally leads to corresponding changes in the fair value measurement of the Partnership’s derivative contracts.

 The Partnership follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. ASC 820-10 applies to equity issued in business combinations and the initial recognition of asset retirement obligations for which fair value is used.

The Partnership utilizes ASC Topic 718, “Compensation—Stock Compensation,” to value units issued for compensation purposes. Measurement of equity-based payment transactions with employees is generally based on the grant date fair value of the equity instruments issued.

Asset retirement cost estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these liabilities as Level 3. 

The Partnership utilizes ASC 805-10 to identify and record the fair value of assets and liabilities acquired in a business combination. New assets measured at fair value during the six months ended June 30, 2013 relate to an acquisition of certain oil and natural gas properties in exchange for approximately 1.4 million common units, valued at $28 million using the closing trading price at date of issuance and an acquisition of certain oil and natural gas properties in exchange for $8.1 million in cash based upon the discounted cash flows associated with the properties’ estimated proved reserves (using various analyses with discount factors ranging from 8% to 15%). The inputs used by management for the fair value measurements of these acquired oil and gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets.

The carrying amount of the revolving long-term debt of $48.0 million as of June 30, 2013 approximates fair value because the Partnership’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The revolving long-term debt is classified as a Level 2 item within the fair value hierarchy.

13

5.  Derivative Contracts

To reduce the impact of fluctuations in oil and natural gas prices on the Partnership’s revenues, or to protect the economics of property acquisitions, the Partnership periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized.  These transactions may include price swaps whereby the Partnership will receive a fixed price for its production and pay a variable market price to the contract counterparty.  Additionally, the Partnership may enter into collars, whereby it receives the excess, if any, of the fixed floor price over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price.  In addition, the Partnership purchases options, such as puts, as a way to manage its exposure to fluctuating prices.  These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations.  It is never the Partnership’s intention to enter into derivative contracts for speculative trading purposes.

Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date.  The Partnership records derivative assets and liabilities by counterparty, by commodity and by type of derivative contract.  Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met.  The Partnership has elected not to designate its current derivative contracts as hedges.  Therefore, changes in the fair value of these instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the condensed statements of operations.

Commodity derivative positions at June 30, 2013 were as follows:

Oil put options:
Year	Volumes (Bbls)		Floor Price
July 1, - December 31, 2013		2,119	$	80.00
2014		26,403	$	80.00

Natural gas put options:
Year	Volumes (MMBtu)		Floor Price
July 1, - December 31, 2013		148,385	$	3.50
2014		476,309	$	3.50
2015		798,853	$	3.50
2016		930,468	$	3.50

Natural gas liquids put options:
Year	Volumes (Bbls)		Average Floor Price
July 1, - December 31, 2013		25,412	$	28.65
2014		63,409	$	28.66

Oil swaps:
Year	Volumes (Bbls)		Fixed Price per Bbl
July 1, - December 31, 2013		18,439	$	93.05
2014		17,324	$	90.20
2015		39,411	$	88.90
2016		36,658	$	86.00

Natural gas swaps:
Year	Volumes (MMBtu)		Avg Price per MMBtu		Range
July 1, - December 31, 2013		814,337	$	3.66		$3.60	-	$3.69
2014		1,224,147	$	4.09			$4.09
2015		800,573	$	4.25			$4.25
2016		629,301	$	4.37			$4.37

Natural gas liquid swaps:
Year	Volumes (Bbls)		Avg Price		Range
July 1, - December 31, 2013		314,048	$	35.48		$34.72	-	$40.71
2014		541,835	$	34.94		$34.60	-	$39.39

14

 The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2013 (in thousands):

Description	Active Market for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)		Total Carrying Value
Oil and natural gas swaps	$	-	$	536		$	-	$	536
Natural gas liquids swaps		-		-			1,066		1,066
Oil, natural gas and liquids put options		-		-			800		800
Total net financial assets	$	-	$	536		$	1,866	$	2,402
Current asset	$	-	$	169		$	898	$	1,067
Long-term asset				425			968		1,393
Current liability				(58	)		-		(58	)
Total net financial assets	$	-	$	536		$	1,866	$	2,402

The following table sets forth a reconciliation of changes in the fair value of the Partnership’s derivative contracts classified as Level 3 in the fair value hierarchy (in thousands): 

	Significant Unobservable Inputs (Level 3) Three Months Ended June 30,						Significant Unobservable Inputs (Level 3) Six Months Ended June 30,
	2013			2012			2013			2012
Beginning balance	$	(2,854	)	$	(458	)	$	(112	)	$	(1,198	)
Realized gains (losses)		92			1,031			(223	)		1,206
Unrealized gains (losses)		4,720			6,465			1,978			7,205
Settlements paid (received)		(92	)		(1,031	)		223			(1,206	)
Ending balance	$	1,866		$	6,007		$	1,866		$	6,007
Change in unrealized gains (losses) included in earnings related to derivatives still held as of June 30, 2013 and 2012	$	4,720		$	6,465		$	1,978		$	7,205

6.  Income Taxes

Income taxes are reflected in these financial statements during the periods in which the IPO Properties were owned by a taxable entity. Since the Partnership is not a taxable entity, no income taxes have been provided for the periods following completion of the Offering. Upon the Partnership becoming a non-taxable entity, the Partnership recognized a tax benefit related to the change in tax status of approximately $12.1 million.

7.  Equity-based Compensation

On February 13, 2013, the Partnership granted 367,500 units of restricted common units to consultants, officers and other employees. Disposition of the units is restricted until the later of the termination of the subordination period or December 31, 2015. The award was valued at the IPO price of $20.00 per common unit and charged to equity-based compensation in general and administrative expenses at the date of the award. The restricted units do not contain a future service requirement from the recipients. For periods prior to February 13, 2013, an allocated amount of New Source Energy stock-based compensation was recognized in the Partnership’s financial statements.

Accordingly, the Partnership recorded the following equity-based compensation expense for the periods ended June 30, 2013 and 2012 (in thousands):

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Total equity-based compensation		-		3,148		7,738		6,297
Equity-based compensation allocated from New Source Energy		-		3,148		388		6,297

15

8.  Acquisition of Properties from New Source Energy and Other Parties

On March 29, 2013, the Partnership entered into a Contribution Agreement between the Partnership and New Source Energy, pursuant to which New Source Energy contributed certain producing and undeveloped oil and gas properties in the Luther field in Oklahoma to the Partnership in exchange for 348,000 common units.  On March 29, 2013, the Partnership entered into a Contribution Agreement  between the Partnership and Scintilla, LLC, pursuant to which New Source Energy contributed certain producing and undeveloped oil and gas properties in the Golden Lane and Luther fields in Oklahoma to the Partnership in exchange for 976,500 common units. On March 29, 2013, the Partnership entered into a Contribution Agreement between the Partnership and W.K. Chernicky, LLC, pursuant to which New Source Energy contributed certain producing and undeveloped oil and gas properties in the Golden Lane and Luther fields in Oklahoma to the Partnership in exchange for 54,000 common units. The acquisitions were recorded at fair value based on the future cash flow of the estimated reserves of the properties acquired. This amount approximated the fair value of the units issued in connection with the transactions of $28 million.

The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands):

Proved oil and natural gas properties including related equipment	$	29,316
Future abandonment costs		(1,333	)
Fair value of net assets acquired	$	27,983

On May 31, 2013, the Partnership completed an acquisition of certain oil and gas properties located in Oklahoma from New Source Energy, pursuant to an Assignment, Bill of Sale and Conveyance from NSEC in favor of the Partnership. As consideration for the assets, the Partnership paid approximately $8.1 million in cash to NSEC, which approximates fair value, based on the future expected cash flow of the estimated reserves of the properties acquired. The acquisition closed on May 31, 2013, with an effective date of May 1, 2013.

The allocation of the purchase price to fair value of the acquired assets and liabilities is as follows (in thousands):

Proved oil and natural gas properties	$	8,166
Future abandonment costs		(19	)
Fair value of net assets acquired	$	8,147

 

Pro Forma Operating Results

The following table reflects the unaudited pro forma results of operations as though the above acquisitions had occurred on January 1, 2012. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
	(in thousands)
Revenues		10,844		10,958		22,847		24,087
Net income (loss)		8,211		3,135		7,611		3,288

The amounts of revenues and revenues in excess of direct operating expenses included in our statements of operations for the acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes.

	Three months ended June 30, 2013		Six months ended June 30, 2013
	(in thousands)
Revenues		2,692		2,777
Excess of revenues over direct operating expenses		1,286		1,333

16

9.General and Administrative Expenses

On February 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among New Source Energy, the Partnership and our general partner. Pursuant to the Omnibus Agreement, New Source Energy provides management and administrative services for the Partnership and our general partner. From the closing of the Offering through December 31, 2013, the Partnership will pay New Source Energy a quarterly fee of $675,000 for the provision of such services. The Partnership recorded a prorated fee of $352,500 for the period from February 13, 2013 through March 31, 2013 in its general and administrative expenses in the quarter ended March 31, 2013. After December 31, 2013, in lieu of the quarterly fee, our general partner will reimburse New Source Energy, on a quarterly basis, for the actual direct and indirect expenses it incurs in its performance under the Omnibus Agreement, and the Partnership will reimburse our general partner for such payments it makes to New Source Energy. Prior to February 13, 2013, the Partnership’s financial statements reflected an allocated portion of the general and administrative expenses of the owner of the IPO Properties.

10. Commitments and Contingencies

Commitments

As part of the transactions described in Notes 1 and 2, the Partnership acquired rights to participate in the 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, as set forth in Note 2, Related Party Transactions.

Legal Matters

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

In the case of Mattingly v. Equal Energy, LLC, New Dominion is a named defendant. In this case, the plaintiffs assert claims on behalf of a class of royalty owners in wells operated by New Dominion and others from which natural gas is sold by New Dominion to Scissortail Energy, LLC. The plaintiffs assert that royalties to the class should be paid based upon the price received by Scissortail for the gas and its components at the tailgate of the plant, rather than the price paid by Scissortail at the wellhead where the gas is purchased. The plaintiffs assert a variety of breach of contract and tort claims. The case was originally filed in the District Court of Creek County, Oklahoma was removed by the defendants to the federal court but was remanded to state court on August 1, 2011.

 If a liability does attach to New Dominion as operator, New Dominion would look to the working interest owners to pay their proportionate share of any liability. While the outcome and impact on the Partnership of this proceeding cannot be predicted with certainty, management believes a range of loss from $10,000 to $250,000 may be reasonably possible.

The Partnership may be involved in other various routine legal proceedings incidental to its business from time to time. However, there were no other material pending legal proceedings to which the Partnership is a party or to which any of its assets are subject.

11.  Subsequent Events

On July 18, 2013, our general partner’s board of directors approved a prorated cash distribution of $0.55 per unit payable on August 15, 2013 to unitholders of record on August 1, 2013.  This distribution corresponds to a 5% increase above the minimum quarterly distribution of $0.525 per unit, or $2.10 on an annualized basis.

On July 23, 2013, the Partnership acquired certain producing and undeveloped oil and gas properties in the Golden Lane field in Oklahoma from Scintilla, LLC for $3.8 million in cash. 

On July 25, 2013, the Partnership acquired certain producing and undeveloped oil and gas properties in the Golden Lane field in Oklahoma from Orion Exploration Partners, LLC and Orion Exploration LLC for $3.25 million in cash.   

17

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

This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains a discussion of our business, including a general overview of our properties, our results of operations, our liquidity and capital resources, and our quantitative and qualitative disclosures about market risk. The following discussion should be read in conjunction with our accompanying interim financial statements and related notes, included elsewhere in this report and prepared in accordance with accounting principles generally accepted in the United States of America and our financial statements, related notes, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2012.

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 on Form 10-Q. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report on Form 10-Q, 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 the front of this Quarterly Report on Form 10-Q.

Overview

We are a Delaware limited partnership formed in October 2012 by New Source Energy to own and acquire oil and natural gas properties in the United States. 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. Our properties consist of non-operated working interests in the Misener-Hunton formation, a conventional resource reservoir located in east-central Oklahoma. This formation has a 90-year history of exploration and development and thousands of wellbore penetrations that have led to more accurate geologic mapping. The estimated proved reserves on our properties were approximately 14.2 MMBoe, as of December 31, 2012, of which approximately 61% were classified as proved developed reserves and of which approximately 76% were comprised of oil and natural gas liquids.

On March 29, 2013, we completed an acquisition, with an effective date of March 1, 2013, of certain oil and gas properties located in Oklahoma (the "March Acquired Properties") from New Source Energy, Scintilla, and W.K. Chernicky, LLC, an Oklahoma limited liability company. As consideration for the March Acquired Properties, we issued an aggregate of 1,378,500 common units representing limited partner interests in the Partnership. The March Acquired Properties are located in the Golden Lane Field, where the properties we acquired in connection with our initial public offering (the "IPO Properties") are located, and in the Luther Field, which is adjacent to the Golden Lane Field. The March Acquired Properties had estimated proved reserves of 3.9 MMBoe as of December 31, 2012, of which 53% were proved developed, 10% were oil and 54% were natural gas liquids.

In addition, on May 31, 2013, we completed an acquisition of certain oil and gas properties located in Oklahoma (the “the May Acquired Properties”) from New Source Energy, pursuant to an Assignment, Bill of Sale and Conveyance. As consideration for the May Acquired Properties, we paid a total of $7,055,683.80 in cash to New Source Energy, representing a reimbursement of the costs incurred by New Source Energy to acquire and develop the May Acquired Properties through May 22, 2013. The acquisition of the May Acquired Properties closed on May 31, 2013, with an effective date of May 1, 2013. The May Acquired Properties are also located in the Golden Lane field and had estimated proved reserves of 1.1 MMBoe as of December 31, 2012, of which 3% are oil and 59% are natural gas liquids.

 Average net daily production for the three and six month periods ending June 30, 2013 was 3,523 Boe/d and 3,333 Boe/d, respectively.

18

Summary Operating Data

The following table presents summary information regarding our historical operating data.  For the three and six months ended June 30, 2012, the data below reflects results attributable to the IPO Properties.  For the three and six months ended June 30, 2013, the data below reflects results attributable to the IPO Properties for the entire period and acquired properties from the closing date of their respective acquisition forward.

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Net Sales Data:
Oil (Bbls)		18,059		16,788		31,134		31,386
Natural gas (Mcf)		658,792		547,623		1,199,897		1,120,374
Natural gas liquids (Bbls)		192,740		181,242		372,206		360,178
Total crude oil equivalent (Boe)(1)		320,598		289,301		603,323		578,293
Average daily volumes (Boe/d)		3,523		3,179		3,333		3,195
Average Sales Price (Excluding Derivatives):
Crude oil (per Bbl)	$	90.59	$	90.66	$	91.03	$	94.98
Natural gas (per Mcf)	$	4.01	$	2.12	$	3.71	$	2.29
Natural gas liquids (per Bbl)	$	33.05	$	30.21	$	34.19	$	35.08
Average equivalent price (per Boe)	$	33.22	$	28.19	$	33.16	$	31.45
Expenses (per Boe):
Lease operating expenses	$	6.29	$	5.03	$	5.47	$	4.73
Workover expenses	$	2.52	$	1.59	$	3.27	$	1.59
Production taxes	$	1.52	$	1.06	$	2.39	$	1.13
General and administrative	$	3.89	$	14.26	$	16.74	$	14.62
Depreciation, depletion and amortization	$	11.16	$	12.79	$	11.22	$	13.22

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

19

Results of Operations — Three Months Ended June 30, 2013 and 2012

Oil, Natural Gas & Natural Gas Liquids Revenues. Revenues from oil and natural gas operations were approximately $10.6 million for the three months ended June 30, 2013, an increase of $2.5 million, or 31%, compared to the three months ended June 30, 2012. Of the total revenues generated during the three months ended June 30, 2013, approximately 60% were generated through natural gas liquids sales, approximately 25% were generated through natural gas sales and approximately 15% were generated through oil sales. The increase in revenues was primarily due to the acquisitions of oil and gas properties during 2013.

The following were specifically related to the impact of production and price levels on revenues recorded during the periods:

●  the average realized oil price was $90.59 per Bbl during the three months ended June 30, 2013, approximately the same as the $90.66 per Bbl during the three months ended June 30, 2012; 

●  total oil production was 18,059 Bbls for the three months ended June 30, 2013, an increase of 8% from 16,788 Bbls for the three months ended June 30, 2012; 

●  the average realized natural gas price was $4.01 per Mcf during the three months ended June 30, 2013, an increase of 89% from $2.12 per Mcf during the three months ended June 30, 2012; 

●  total natural gas production was 658,792 Mcf for the three months ended June 30, 2013, an increase of 20% from 547,623 Mcf for the three months ended June 30, 2012; 

●  the average realized natural gas liquids price was $33.05 per Bbl during the three months ended June 30, 2013, an increase of 9% from $30.21 per Bbl during the three months ended June 30, 2012; and 

●  total natural gas liquids production was 192,740 Bbls for the three months ended June 30, 2013, an increase of 6% from 181,242 Bbls for the three months ended June 30, 2012. 

Lease operating expenses. Lease operating expenses were $2.0 million for the three months ended June 30, 2013, an increase of 39% or $0.5 million from the $1.5 million of lease operating expenses incurred during the three months ended June 30, 2012. Lease operating expenses increased due to the acquisitions of oil and gas properties completed in 2013.

Workover expenses. Workover expenses increased $0.3 million, or 76%, to $0.8 million during the three months ended June 30, 2013 from $0.5 million during the three months ended June 30, 2012. Increased workover expense increased due to a focus on workovers to increase production from existing wells.

Production taxes. Production taxes increased $0.2 million, or 50%, to $0.5 million during the three months ended June 30, 2013 from $0.3 million during the three months ended June 30, 2012. The increase was due to fewer production tax incentives in the 2013 period.

General and administrative expenses. General and administrative expense decreased $2.9 million, or 70%, to $1.2 million during the three months ended June 30, 2013 from $4.1 million during the three months ended June 30, 2012. The decrease in general and administrative expense was related to zero equity-based compensation incurred in the three months ended June 30, 2013.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was relatively flat between periods and decreased $0.1 million, or 3%, to $3.6 million during the three months ended June 30, 2013 from $3.7 million during the three months ended June 30, 2012.

Interest expense. Interest expense decreased $0.3 million, or 38%, to $0.5 million during the three months ended June 30, 2013 from $0.8 million during the three months ended June 30, 2012. The decrease is due to lower outstanding amounts borrowed on the credit facility in the 2013 period.

Realized and unrealized gains from derivatives. Realized and unrealized losses from derivatives were $6.2 million during the three months ended June 30, 2013 compared to gains of $7.5 million during the three months ended June 30, 2012. This was primarily the result of commodity contract prices falling significantly on the longer-term contracts during the second quarter of 2013.

Net Income. The Partnership recorded net income of $8.2 million during the three months ended June 30, 2013 compared to net income of $2.9 million during the three months ended June 30, 2012. The net income is primarily due to derivatives gains of $6.2 million recorded during the second quarter of 2013.

20

Results of Operations — Six Months Ended June 30, 2013 and 2012

Oil, Natural Gas & Natural Gas Liquids Revenues. Revenues from oil and natural gas operations were approximately $20.0 million for the six months ended June 30, 2013, an increase of $1.8 million, or 10%, compared to the six months ended June 30, 2012. Of the total revenues generated during the six months ended June 30, 2013, approximately 64% were generated through natural gas liquids sales, approximately 22% were generated through natural gas sales and approximately 14% were generated through oil sales. The increase in revenues was primarily due to the acquisitions of oil and gas properties during 2013.

The following were specifically related to the impact of production and price levels on revenues recorded during the periods:

●  the average realized oil price was $91.03 per Bbl during the six months ended June 30, 2013, a decrease of 4% from $94.98 per Bbl during the six months ended June 30, 2012; 

●  total oil production was 31,134 Bbls for the six months ended June 30, 2013, a decrease of 1% from 31,386 Bbls for the six months ended June 30, 2012; 

●  the average realized natural gas price was $3.71 per Mcf during the six months ended June 30, 2013, an increase of 62% from $2.29 per Mcf during the six months ended June 30, 2012; 

●  total natural gas production was 1,199,897 Mcf for the six months ended June 30, 2013, an increase of 7% from 1,120,374 Mcf for the six months ended June 30, 2012; 

●  the average realized natural gas liquids price was $34.19 per Bbl during the six months ended June 30, 2013, a decrease of 3% from $35.08 per Bbl during the six months ended June 30, 2012; and 

●  total natural gas liquids production was 372,206 Bbls for the six months ended June 30, 2013, an increase of 3% from 360,178 Bbls for the six months ended June 30, 2012. 

Lease operating expenses. Lease operating increased $0.6 million, or 21% to $3.3 million during the six months ended June 30, 2013 from $2.7 million during the six months ended June 30, 2012. Lease operating expenses increased due to the acquisitions of oil and gas properties completed in 2013.

Workover expenses. Workover expenses increased $1.1 million, or 115%, to $2.0 million during the six months ended June 30, 2013 from $0.9 million during the six months ended June 30, 2012. Workover expenses increased due to a focus on workovers to increase production from existing wells.

Production taxes. Production taxes increased $0.8 million, or 121%, to $1.4 million during the six months ended June 30, 2013 from $0.6 million during the six months ended June 30, 2012. The increase was due to tax adjustments from prior periods and fewer production tax incentives in the 2013 period.

General and administrative expenses. General and administrative expense increased $1.6million, or 19%, to $10.1 million during the six months ended June 30, 2013 from $8.5 million during the six months ended June 30, 2012. The increase in general and administrative expense was related to higher equity-based compensation in the 2013 period.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased $0.8 million, or 11%, to $6.8 million during the six months ended June 30, 2013 from $7.6 million during the six months ended June 30, 2012. This decrease was the result of increased reserves in the 2013 period attributable to our acquisitions of oil and gas properties.

Interest expense. Interest expense increased $1.0 million, or 61%, to $2.6 million during the six months ended June 30, 2013 from $1.6 million during the six months ended June 30, 2012. The increase was primarily due to a write off of $1.4 million of loan fees associated with extinguishing the $70 million New Source Energy credit facility in connection with the Partnership's initial public offering.

Realized and unrealized gains from derivatives. Realized and unrealized gains from derivatives were $0.9 million during the six months ended June 30, 2013 compared to gains of $8.4 million during the six months ended June 30, 2012. This was primarily the result of prices of natural gas prices falling during the second quarter of 2012 and commodity contract prices falling significantly on longer-term contracts in the second quarter of 2013.

Net Income. The Partnership recorded net income of $6.8 million during the six months ended June 30, 2013 compared to net income of $2.8 million during the six months ended June 30, 2012. The net income is primarily due to the income tax benefit associated with a change in tax status of $12.1 million offset by $7.7 million of equity-based compensation recorded during the six months ended June 30, 2012.

21

Cash Flow – Six Months Ended June 30, 2013 and 2012

The Partnership recorded cash flows provided by operations of $2.7 million during the six months ended June 30, 2013 compared to $12.3 million during the six months ended June 30, 2012. Cash flows provided by operations in the six months ended June 30, 2013 were primarily impacted by $7.0 million of accounts receivable being distributed immediately prior to the initial public offering. Cash flows used in investing activities were $12.2 million during the six months ended June 30, 2013 compared to $6.5 million during the six months ended June 30, 2012.

Cash flows from investing activities in the 2013 period primarily reflect oil and gas property acquisitions and development activities. Cash flows provided by financing activities were $10.3 million during the six months ended June 30, 2013 compared to cash flows used in financing activities of $5.8 million during the six months ended June 30, 2012.

Cash flows from financing activities in the 2013 period were primarily the result of proceeds from the offering and borrowings from the credit facility offset by debt repayment of the New Source Energy credit facility and the subordinated note, distributions to unit holders, and the cash payment to New Source Energy for the IPO Properties. 

Capital Resources and Liquidity

Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We may also have the ability to issue additional equity and debt securities as needed. To date, our primary use of capital has been for the acquisition, development and maintenance of oil and natural gas properties.

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order 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.

We may borrow to make distributions to our unitholders, for example, in circumstances where we believe 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. In addition, we plan to hedge a significant portion of our production. We generally are required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and natural gas industry, we do not generally receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the commodity derivative contracts, we are required to pay the derivative counterparty the difference between the fixed price in the commodity derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production, and as a result, we may not grow as quickly as other oil and natural gas entities or at all.

We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. Because our proved reserves and production decline continually over time and because we own a limited amount of undeveloped properties, we may need to make acquisitions to sustain our level of distributions to unitholders over time. 

If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our revolving credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our revolving credit facility or other future indebtedness. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

22

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). The primary purpose of maintenance capital is to maintain our production and asset base at a steady level over the long term to maintain our distributions to our unitholders. For the year ending December 31, 2013, we estimate that our maintenance capital expenditures will be approximately $10.2 million which is the amount we believe is necessary to spend annually to drill our proved undeveloped locations and maintain our producing wells, we will be able to at least maintain our current production through 2016. We intend to pay for maintenance capital expenditures from operating cash flow. We make an estimate of maintenance capital expenditures at least annually and whenever an event occurs that is likely to result in an adjustment to our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business.

Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner which 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 commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions. 

Based on our current oil, natural gas and NGL price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for the year ending December 31, 2013. However, future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

Revolving Credit Facility

In connection with our Offering, we entered into a revolving credit facility by and among us, as borrower, the Bank of Montreal, as administrative agent for the lenders party thereto, and the other lenders party thereto. The revolving credit facility is a four-year, $150 million senior secured revolving credit facility with a current borrowing base of $75.0 million. In addition, we assumed approximately $70.0 million of New Source Energy’s indebtedness under its credit facility attributable to the IPO Properties. We used a portion of the net proceeds from our IPO, together with $15.0 million of borrowings under our revolving credit facility to (i) repay in full such assumed debt and (ii) make a distribution to New Source Energy as partial consideration for the contribution by New Source Energy of the IPO Properties and certain commodity derivative contracts. As additional consideration for its contribution of the IPO Properties to us in connection with the Offering, we issued a $25.0 million note payable to New Source Energy.

On February 28, 2013, we entered into a First Amendment to our revolving credit facility, which added a lender, increased our borrowing base from $30.0 million to $60.0 million, and increased the lenders’ aggregate commitment from $60.0 million to $150.0 million. As a condition precedent to effectiveness of the First Amendment, we repaid the $25.0 million subordinated note issued to New Source Energy in full with borrowings under our revolving credit facility. On June 25, 2013, the Partnership entered into a Second Amendment (the “Second Amendment”) to its Credit Agreement. The Second Amendment (i) added two lenders under the Credit Agreement, and (ii) increased the Partnership’s borrowing base under the Credit Agreement from $60 million to $75 million. As of June 30, 2013, we had approximately $48.0 million of outstanding borrowings under our revolving credit facility.

Borrowings under the revolving credit facility bear interest at a base rate (a rate based off of the higher of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) 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 our borrowing base utilization). Interest will be payable quarterly, or if LIBOR applies, it may be payable at more frequent intervals. In addition, the unused portion of our revolving credit facility is subject to a commitment fee of 0.50%.

The revolving credit facility requires us to maintain a minimum interest coverage ratio of not less than 2.50 to 1.00, a current ratio of not less than 1.0 to 1.0 and a ratio of total debt to EBITDAX of not more than 3.50 to 1.00. In addition, the credit agreement governing the revolving credit facility contains customary affirmative and negative covenants for transactions of this nature, including, but not limited to restrictions on: (i) incurrence of debt and liens (in each case, subject to certain exceptions); (ii) investments, acquisitions, mergers and asset sales (in each case, subject to certain exceptions); (iii) payments of dividends and distributions (with exceptions for distributions of available cash consistent with the partnership agreement, so long as (a) no event of default has occurred and is continuing, or would result therefrom, and (b) our borrowing base utilization does not exceed 90%) and (iv) certain modifications to organizational documents and material agreements, subject to certain exceptions. If we should fail to perform our obligations under these and other covenants, the revolving commitments could terminate and any outstanding borrowings under the revolving credit agreement, together with accrued interest, could become immediately due and payable. At June 30, 2013, we were in compliance with all covenants of the revolving credit agreement.

Debt under the revolving credit facility is secured by a security interest in, among other things, (i) oil and gas properties representing at least 80% of the total proved value, and 90% of the total proved developed producing value, of all of our oil and gas properties, (ii) all of our present and future personal property and (iii) the capital stock of any future subsidiaries.

23

Our revolving credit facility is reserve-based, permitting us to borrow an amount up to the borrowing base, which is primarily based on the value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil prices at such time, as adjusted for the impact of our derivative contracts. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.

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

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, natural gas and NGL prices. Oil, natural gas and NGL prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on oil, natural gas and NGL prices and our ability to maintain and increase production through acquisitions and exploitation and development projects.

New Source Energy has contributed commodity derivative contracts to us covering approximately 90% of our estimated oil and natural gas production from our total proved developed producing reserves as of December 31, 2012 and approximately 50% of our estimated oil and natural gas production from our total proved undeveloped reserves as of December 31, 2012 for the years ending December 31, 2013, 2014, 2015 and 2016, based on production estimates contained in our reserve report. New Source Energy has also contributed to us, commodity derivative contracts covering approximately 90% of our estimated NGL production from our total proved developed producing reserves as of December 31, 2012 and approximately 50% of our estimated NGL production from our total proved undeveloped reserves as of December 31, 2012 for the years ending December 31, 2013 and 2014, based on production estimates contained in our reserve report. We expect that as the market for NGL-based commodity derivative contracts becomes more developed over time, our ability to cover future NGL production beyond the two-year horizon in place at the closing of the Offering will be strengthened.

Our hedging strategy includes entering into commodity derivative contracts covering approximately 60% to 90% of our estimated total production over a three-to-five year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a derivative contract is terminated prior to its expiration. 

Off Balance Sheet Arrangements

As of June 30, 2013, we had no material off-balance sheet arrangements. We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

Critical Accounting Policies and Estimates

Investors in our partnership should be aware of how certain events may impact our financial results based on the accounting policies in place.  In our management’s opinion, the more significant reporting areas impacted by our management’s judgments and estimates are revenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, impairment of long-lived assets and valuation of equity-based compensation. Our management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.

There have been no material changes in our critical accounting policies and procedures during the six months ended June 30, 2013.  See our disclosure of critical accounting policies in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 3.         Quantitative and Qualitative Disclosures About Market Risk

For discussion of our market risk, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” in our Annual Report on Form 10-K for the year ended December 31, 2012.

24

ITEM 4.       CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our audit committee, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of June 30, 2013. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under 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 SECs rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of June 30, 2013 at the reasonable assurance level due to a material weakness in internal control over financial reporting. The material weakness we identified relates to 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 United States generally accepted accounting principles. In the current period these non-routine transactions impacted the recording of equity based compensation, cash-flow presentations, required business combination disclosures and calculations of earnings (loss) per unit. The material weakness resulted in the recording of adjustments identified by our independent registered public accounting firm to the financial statements for the period ended March 31, 2013. Notwithstanding the existence of the material weakness, 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 United States generally accepted accounting principles.

Management's Remediation Activities

With the oversight of senior management and our audit committee, we have begun to take steps intended to address the underlying causes of the material weakness, primarily through the engagement of outside consulting firms with technical accounting and financial reporting experience, and the implementation and validation of improved accounting and financial reporting procedures.

As of June 30, 2013, we have not yet been able to remediate this material weakness. We do not know the specific timeframe needed to remediate all of the control deficiencies underlying this material weakness. In addition, we may need to incur incremental costs associated with this remediation, primarily due to engagement with such firms, and the implementation and validation of improved accounting and financial reporting procedures. As we continue to evaluate and work to improve its 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 were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our 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.

PART II – OTHER INFORMATION

Item 1.         Legal Proceedings

From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and 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.

25

Refer to Note 10 -Commitments and Contingencies of the financial statements of this Form 10-Q for a discussion of legal proceedings.

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

Item  1A.     Risk Factors

In addition to the other information set forth in this Quarterly Report on Form 10-Q, you should carefully consider the risks discussed in our Annual Report on Form 10-K for the year ended December 31, 2012, which risks could materially affect our business, financial condition, or results of operations. The risks described in this Quarterly Report on Form 10-Q and in our Annual Report on Form 10-K are not the only risks facing our partnership. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

Item  2.        Unregistered Sales of Equity Securities and Use of Proceeds

None not previously disclosed on a Current Report on Form 8-K. 

Item 6.         Exhibits

Exhibit
Number Description

2.1	—	Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. andNew Source Energy Corporation (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Reporton Form 8-K (File No. 001-35809) filed on April 4, 2013).
2.2	—	Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. andScintilla, LLC (Incorporated by reference to Exhibit 2.2 of the Partnership’s Current Report on Form 8-K (FileNo. 001-35809) filed on April 4, 2013).
2.3	—	Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. andW.K. Chernicky, LLC (Incorporated by reference to Exhibit 2.3 of the Partnership’s Current Report on Form 8-K(File No. 001-35809) filed on April 4, 2013).
3.1	—	Certificate of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.1of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013).
3.2	—	First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.(Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809)filed on February 15, 2013).
3.3	—	Certificate of Formation of New Source Energy GP, LLC (Incorporated by reference to Exhibit 3.4 of thePartnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013).
3.4	—	Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC (Incorporated byreference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February15, 2013).
3.5	—	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of New Source Energy GP,LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on March 20, 2013).
10.1	—	Second Amendment to Credit Agreement, dated as of June 25, 2013, by and among the Partnership, as borrower,Bank of Montreal, as administrative agent, Associated Bank, N.A., as syndication agent, and the other lenders partythereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on June 28, 2013).
10.2	—	Purchase and Sale Agreement between New Source Energy Partners L.P. and Scintilla, LLC, dated July 23, 2013Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809)filed on July 29, 2013).

26

31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*	—	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	—	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

27

Exhibit Number		Description
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.

________________________________________

*	Filed herewith.
**	Furnished herewith.
†	Management contract or compensatory plan or arrangement.

28

 SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on August 13, 2013.

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

29

EXHIBIT INDEX

Exhibit
Number Description

2.1	—	Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. andNew Source Energy Corporation (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Reporton Form 8-K (File No. 001-35809) filed on April 4, 2013).
2.2	—	Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. andScintilla, LLC (Incorporated by reference to Exhibit 2.2 of the Partnership’s Current Report on Form 8-K (FileNo. 001-35809) filed on April 4, 2013).
2.3	—	Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. andW.K. Chernicky, LLC (Incorporated by reference to Exhibit 2.3 of the Partnership’s Current Report on Form 8-K(File No. 001-35809) filed on April 4, 2013).
3.1	—	Certificate of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.1of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013).
3.2	—	First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.(Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809)filed on February 15, 2013).
3.3	—	Certificate of Formation of New Source Energy GP, LLC (Incorporated by reference to Exhibit 3.4 of thePartnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013).
3.4	—	Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC (Incorporated byreference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February15, 2013).
3.5	—	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of New Source Energy GP,LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on March 20, 2013).
10.11	—	Second Amendment to Credit Agreement, dated as of June 25, 2013, by and among the Partnership, as borrower,Bank of Montreal, as administrative agent, Associated Bank, N.A., as syndication agent, and the other lenders partythereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on June 28, 2013).
10.12	—	Purchase and Sale Agreement between New Source Energy Partners L.P. and Scintilla, LLC, dated July 23, 2013Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809)filed on July 29, 2013).

31.1*	—	Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
31.2*	—	Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934.
32.1**	—	Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

30

Exhibit Number		Description
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.

________________________________________

*	Filed herewith.
**	Furnished herewith.
†	Management contract or compensatory plan or arrangement.

31