10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

(MARK ONE)

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

For the quarterly period ended September 30, 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 November 14, 2013, the registrant had 9,034,810 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.

NEW SOURCE ENERGY PARTNERS, L.P.

Form 10-Q

Quarter Ended September 30, 2013

TABLE OF CONTENTS

PART I – FINANCIAL INFORMATION
	Item 1.	Financial Statements	7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	19
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28
	Item 4.	Controls and Procedures	29
PART II – OTHER INFORMATION			30
	Item 1.	Legal Proceedings	30
	Item 1A.	Risk Factors	30
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	30
	Item 6.	Exhibits	31
SIGNATURES			32

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, 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;

4

● exploration and development risks;

● 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.

5

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.

6

New Source Energy Partners L.P.

Condensed Balance Sheets

(unaudited, in thousands, except unit amounts)

	September 30, 2013			December 31, 2012
ASSETS
Current assets:
Cash	$	258		$	-
Oil and natural gas sales receivable		7,308			5,621
Oil and natural gas sales receivable-related parties		1,145			42
Derivative assets		443			25
Other current assets		160			-
Total current assets		9,314			5,688
Property and equipment:
Oil and natural gas properties, at cost, using full cost method:
Proved oil and natural gas properties		262,745			202,795
Accumulated depreciation, depletion, and amortization		(124,057	)		(112,372	)
Total property and equipment, net		138,688			90,423
Prepaid drilling and completion costs		4,266			1,000
Loan fees, net		1,476			1,508
Deferred offering costs		-			1,315
Derivative assets		837			-
Total assets	$	154,581		$	99,934
LIABILITIES, PARENT NET INVESTMENT AND PARTNERS' CAPITAL:
Current liabilities:
Accounts payable	$	291		$	-
Accounts payable-related parties		4,510			1,564
Accrued liabilities		209			259
Accrued income taxes		-			103
Derivative obligations		1,556			47
Total current liabilities		6,566			1,973
Long-term related party payables		283			345
Credit facility		67,500			68,000
Derivative obligations		238			107
Asset retirement obligation		3,059			1,510
Deferred tax liability		-			12,024
Total liabilities		77,646			83,959
Commitments and contingencies (See Note 10)
Parent net investment		-			15,975
Partners' capital:
Common units (6,773,500 units outstanding at September 30, 2013)		98,934			-
Subordinated units (2,205,000 units outstanding at September 30, 2013)		(20,595	)		-
General partner's capital (155,102 units outstanding at September 30, 2013)		(1,404	)		-
Total partners' capital		76,935			15,975
Total liabilities, parent net investment and partners' capital	$	154,581		$	99,934

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

7

New Source Energy Partners L.P.

Condensed Statements of Operations

(unaudited, in thousands, except per unit amounts)

 

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
REVENUES
Oil sales		2,044			1,390			4,879			4,371
Natural gas sales		2,582			1,608			7,031			4,177
Natural gas liquids sales		7,805			5,264			20,530			17,900
Total revenues	$	12,431		$	8,262		$	32,440		$	26,448
OPERATING COSTS AND EXPENSES
Oil and natural gas production expenses		3,428			1,133			8,702			4,789
Oil and natural gas production taxes		557			178			1,996			829
General and administrative		1,353			2,504			11,452			10,956
Depreciation, depletion and amortization		4,913			3,409			11,686			11,052
Accretion expense		59			29			145			86
Total operating costs and expenses		10,310			7,253			33,981			27,712
Operating income (loss)		2,121			1,009			(1,541	)		(1,264	)
OTHER INCOME (EXPENSE)
Interest expense		(654	)		(824	)		(3,220	)		(2,422	)
Gain (loss) from derivatives, net		(3,453	)		(1,546	)		(2,597	)		6,866
Income (loss) before income taxes		(1,986	)		(1,361	)		(7,358	)		3,180
Income tax benefit (expense)		-			562			12,126			(1,166	)
Net income (loss)	$	(1,986	)	$	(799	)	$	4,768		$	2,014
ALLOCATION OF NET INCOME (LOSS) FOR THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013:
Net income							$	4,768
Net income prior to purchase of properties from New Source Energy on February 13, 2013							$	5,303
Net loss subsequent to purchase of properties from New Source Energy on February 13, 2013							$	(535	)
Net loss allocable to general partner from February 13, 2013 to September 30, 2013							$	(29	)
Net loss allocable to subordinated units from February 13, 2013 to September 30, 2013							$	(430	)
Net loss allocable to common units from February 13, 2013 to September 30, 2013							$	(76	)
Net loss per common unit from February 13, 2013 to September 30, 2013							$	(0.01	)
Net loss allocable to general partner for the three months ended September 30, 2013	$	(34	)
Net loss allocable to subordinated units for the three months ended September 30, 2013	$	(479	)
Net loss allocable to common units for the three months ended September 30, 2013	$	(1,473	)
Net loss per common unit	$	(0.22	)

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

8

New Source Energy Partners L.P.

Statement of Partners' Capital

For the nine months ended September 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		-			-		(5,582	)		-		(1,818	)		-		(127	)		(7,527	)
Net loss attributable to the period from February 13, 2013 to September 30, 2013		-			-		(76	)		-		(430	)		-		(29	)		(535	)
Balance, September 30, 2013	$	-			6,773,500	$	98,934			2,205,000	$	(20,595	)		155,102	$	(1,404	)	$	76,935

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

9

New Source Energy Partners L.P. 

Condensed Statements of Cash Flows

(unaudited, in thousands)

	Nine months ended September 30,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	4,768		$	2,014
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		11,686			11,052
Write off of loan fees due to debt refinancing		1,436			-
Equity-based compensation		7,738			7,405
Deferred income tax expense (benefit)		(12,023	)		947
Amortization of loan fees		358			453
Accretion expense		145			86
Unrealized gain (loss) on derivatives, net		1,719			(889	)
Payments for derivative option premiums		(1,334	)		-
Changes in operating assets and liabilities:
Oil and natural gas sales receivable		(9,673	)		1,276
Other current assets		(160	)		-
Accounts payable		5,173			475
Accrued liabilities		(50	)		(118	)
Income taxes payable		(103	)		48
Net cash provided by operating activities		9,680			22,749
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for oil and natural gas properties and equipment		(34,218	)		(9,175	)
Net cash used in investing activities		(34,218	)		(9,175	)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on long-term debt		(95,000	)		(3,500	)
Payments for deferred loan costs		(1,762	)		(65	)
Proceeds from sales of common units, net of offering costs		77,880			(492	)
Proceeds from borrowings on long-term debt		69,500			3,000
Distribution to unitholders		(7,527	)		-
Distribution to parent		(18,295	)		(12,517	)
Net cash provided by (used in) financing activities		24,796			(13,574	)
Net change in cash and cash equivalents		258			-
Cash and cash equivalents, beginning of period		-			-
Cash and cash equivalents, end of period	$	258		$	-
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest expense	$	1,476		$	2,087
NON-CASH INVESTING AND FINANCING ACTIVITIES
Capitalized asset retirement obligation	$	1,403		$	26
Decrease in accrued capital expenditures		(258	)		(478	)
Income taxes assumed by parent		-			172
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. 

10

 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.

Basis of Presentation 

The accompanying unaudited condensed financial statements present the financial position of the Partnership at September 30, 2013 and December 31, 2012 and the Partnership’s results of operations and cash flows for the nine months ended September 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 nine months ended September 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. 

11

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 internal 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 nine months ended September 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 September 30, 2013 were computed using the following components:

	Common Units			Subordinated Units			General Partner
Numerator
Net loss (in thousands)	$	(76	)	$	(430	)	$	(29	)
Denominator:
Weighted average units outstanding		6,480,439			2,205,000			154,503
Basic and diluted loss per unit	$	(0.01	)	$	(0.20	)	$	(0.19	)

 

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

	Common Units			Subordinated Units			General Partner
Numerator
Net loss (in thousands)	$	(1,473	)	$	(479	)	$	(34	)
Denominator:
Weighted average units outstanding		6,773,500			2,205,000			155,102
Basic and diluted loss per unit	$	(0.22	)	$	(0.22	)	$	(0.22	)

12

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 September 30, 2013, of which $0.1 million 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, senior secured revolving credit facility. 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 is 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 3.31% per annum at September 30, 2013. As of September 30, 2013, the Partnership had $67.5 million outstanding under the Credit Agreement and, as a result, had $7.5 million of available borrowing capacity. The Partnership was in compliance with all covenants of the Credit Agreement as of September 30, 2013. 

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.

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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 business combinations. New assets measured at fair value during the nine months ended September 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 other acquisitions of certain oil and natural gas properties in exchange for an aggregate of $16.2 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 $67.5 million as of September 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. 

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 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 September 30, 2013 were as follows:

Oil put options: 

Year	Volumes (Bbls)		Floor Price
October 1, - December 31, 2013		1,209	$	80.00
2014		26,403	$	80.00

Natural gas put options: 

Year	Volumes (MMBtu)		Floor Price
October 1, - December 31, 2013		79,985	$	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
October 1, - December 31, 2013		13,862	$	28.65
2014		63,409	$	28.66

Oil swaps: 

Year	Volumes (Bbls)		Fixed Price per Bbl
October 1, - December 31, 2013		8,323	$	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
October 1, - December 31, 2013		387,288	$	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
October 1, - December 31, 2013		153,355	$	35.42	$34.72	-	$40.71
2014		541,835	$	34.94	$34.60	-	$39.39

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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 September 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	$	-	$	451		$	-		$	451
Natural gas liquids swaps		-		-			(1,602	)		(1,602	)
Oil, natural gas and liquids put options		-		-			637			637
Total net financial assets (liabilities)	$	-	$	451		$	(965	)	$	(514	)
Current asset	$	-	$	279		$	164		$	443
Long-term asset		-		364			473			837
Current liability		-		(192	)		(1,364	)		(1,556	)
Long-term liability		-		-			(238	)		(238	)
Total net financial assets (liabilities)	$	-	$	451		$	(965	)	$	(514	)

 

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						Significant Unobservable
	Inputs (Level 3)						Inputs (Level 3)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Beginning balance	$	1,866		$	6,007		$	(112	)	$	(1,198	)
Gains (losses)		(3,277	)		(1,348	)		(1,522	)		7,063
Settlements paid (received)		446			(4,761	)		669			(5,967	)
Ending balance	$	(965	)	$	(102	)	$	(965	)	$	(102	)
Losses included in earnings related to derivatives still held as of September 30, 2013 and 2012	$	(2,677	)	$	(102	)	$	(884	)	$	(102	)

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.

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

 

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Total equity-based compensation	$	-	$	1,108	$	7,738	$	7,405
Equity-based compensation allocated from New Source Energy	$	-	$	1,108	$	388	$	7,405

 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 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 $8.0 million in cash, after purchase price adjustments, 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

On July 23, 2013, the Partnership completed an acquisition of certain producing and undeveloped oil and gas properties in the Golden Lane field in Oklahoma from Scintilla for $5.0 million in cash, after purchase price adjustments, which approximates fair value based on future expected cash flow of the estimated reserves of the properties acquired. The acquisition closed on July 23, 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	$	4,866
Future abandonment costs		(8	)
Fair value of net assets acquired	$	4,858

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 $3.0 million in cash, after purchase price adjustments,which approximates fair value based on future expected cash flow of the estimated reserves of the properties acquired. The acquisition closed on July 25, 2013, with an effective date of June 1, 2013.

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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	$	3,230
Future abandonment costs		(24	)
Fair value of net assets acquired	$	3,206

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 September 30,						Nine months ended September 30,
	2013			2012			2013		2012
	(in thousands)
Revenues	$	12,494		$	11,104		$	35,516	$	35,191
Net income (loss)	$	(1,998	)	$	(3,706	)	$	5,650	$	2,797

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 September 30, 2013		Nine months ended September 30, 2013
	(in thousands)
Revenues	$	4,197	$	6,974
Excess of revenues over direct operating expenses	$	2,180	$	3,350

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.

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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 October 4, 2013, the Partnership acquired certain producing and undeveloped oil and gas properties in the Southern Dome field from Scintilla for total consideration of $13.6 million consisting of $5.0 million in cash and 414,045 common units, valued at $20.79 per unit or an aggregate of $8.6 million, that were delivered in November.

On October 21, 2013, our general partner’s board of directors approved a cash distribution of $0.575 per unit payable on November 15, 2013 to unitholders of record on November 1, 2013.  

On October 29, 2013, the Partnership entered into a Third Amendment to its Credit Agreement (the “Third Amendment”). The Third Amendment (i) added a lender under the Credit Agreement, and (ii) increased the Partnership’s borrowing base under the Credit Agreement from $75 million to $87.5 million.

On November 12, 2013, the Partnership acquired the partnership interests in MCE, LP from its current owners (the “Contributors”) for approximately $43.6 million in total initial consideration to be paid in approximately $3.8 million in cash and 1,847,265 NSLP common units, valued using a volume weighted average trading price for the period between August 21, 2013 and November 11, 2013 of $21.55 per common unit. MCE, LP is an oilfield services company that specializes in increasing efficiencies and safety in drilling and completion processes. MCE, LP is considered to be a related party of the Partnership as the Chief Executive Officer of the Partnership, who is also the majority owner of New Source Energy GP, LLC, is one of the Contributors.

The Contributors retained 100 Class B Units in MCE, LP, which entitle them to incentive distributions of cash distributed by MCE, LP on its partnership interests above specified thresholds, up to a maximum of 50% at the highest level of distributions.

        In addition to the initial consideration, the Contributors are entitled to receive an earn out payment on May 1, 2015. Any earn out payment will be calculated based on a specified multiple of the annualized EBITDA generated by MCE, LP for the nine months ended March 31, 2015 less certain adjustments and will be satisfied using the Partnership’s common units, valued using a trailing twenty-day volume weighted average trading price as of three trading days prior to the issuance of such common units.

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. 

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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 approximately $8 million, after purchase price adjustments, 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.

On July 23, 2013, the Partnership completed an acquisition of certain producing and undeveloped oil and gas properties in the Golden Lane field in Oklahoma from Scintilla for $5.0 million in cash, after purchase price adjustments. The transaction closed on July 23, 2013 with an effective date of May 1, 2013.

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 $3.0 million in cash, after purchase price adjustments. The acquisition closed on July 25, 2013 with an effective date of June 1, 2013.

On October 4, 2013, the Partnership completed an acquisition of working interests in 25 producing wells and related undeveloped leasehold rights in the Southern Dome Field in Oklahoma County, Oklahoma from Scintilla for $5.0 million in cash and 414,045 common units that were delivered in November.

Average net daily production for the three and nine month periods ending September 30, 2013 was 3,937 Boe/d and 3,537 Boe/d, respectively.

Summary Operating Data 

The following table presents summary information regarding our historical operating data.  For the three and nine months ended September 30, 2012, the data below reflects results attributable to the IPO Properties.  For the three and nine months ended September 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.

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	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Net Sales Data:
Oil (Bbls)		19,900		15,545		51,124		46,931
Natural gas (Mcf)		755,889		589,869		1,955,786		1,710,243
Natural gas liquids (Bbls)		216,225		176,178		588,431		536,356
Total crude oil equivalent (Boe)(1)		362,197		290,035		965,519		868,328
Average daily volumes (Boe/d)		3,937		3,153		3,537		3,169
Average Sales Price (Excluding Derivatives):
Crude oil (per Bbl)	$	102.25	$	89.42	$	95.43	$	93.14
Natural gas (per Mcf)	$	3.42	$	2.73	$	3.59	$	2.44
Natural gas liquids (per Bbl)	$	36.10	$	29.88	$	34.89	$	33.37
Average equivalent price (per Boe)	$	34.32	$	28.49	$	33.60	$	30.46
Expenses (per Boe):
Lease operating expenses	$	7.58	$	3.49	$	6.26	$	4.32
Workover expenses	$	1.89	$	0.42	$	2.75	$	1.20
Production taxes	$	1.54	$	0.61	$	2.07	$	0.95
General and administrative	$	3.74	$	8.63	$	11.86	$	12.62
Depreciation, depletion and amortization	$	13.56	$	11.75	$	12.10	$	12.73

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

 

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

Oil, Natural Gas & Natural Gas Liquids Revenues. Revenues from oil and natural gas operations were approximately $12.4 million for the three months ended September 30, 2013, an increase of $4.2 million, or 50%, compared to revenues of $8.2 million for the three months ended September 30, 2012. Of the total revenues generated during the three months ended September 30, 2013, approximately 63% were generated through natural gas liquids sales, approximately 21% were generated through natural gas sales and approximately 16% were generated through oil sales. The increase in revenues was primarily due to the acquisitions of oil and natural gas properties during 2013 and higher commodity prices realized 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 $102.25 per Bbl during the three months ended September 30, 2013, an increase of 14% from $89.42 per Bbl during the three months ended September 30, 2012; 

●  total oil production was 19,900 Bbls for the three months ended September 30, 2013, an increase of 29% from 15,545 Bbls for the three months ended September 30, 2012; 

●  the average realized natural gas price was $3.42 per Mcf during the three months ended September 30, 2013, an increase of 25% from $2.73 per Mcf during the three months ended September 30, 2012; 

●  total natural gas production was 755,889 Mcf for the three months ended September 30, 2013, an increase of 28% from 589,869 Mcf for the three months ended September 30, 2012; 

●  the average realized natural gas liquids price was $36.10 per Bbl during the three months ended September 30, 2013, an increase of 21% from $29.88 per Bbl during the three months ended September 30, 2012; and 

●  total natural gas liquids production was 216,225 Bbls for the three months ended September 30, 2013, an increase of 23% from 176,178 Bbls for the three months ended September 30, 2012. 

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Lease operating expenses. Lease operating expenses were $2.8 million for the three months ended September 30, 2013, an increase of 172% or $1.7 million from the $1.1 million of lease operating expenses incurred during the three months ended September 30, 2012. Lease operating expenses increased due to the acquisitions of oil and natural gas properties completed in 2013.

Workover expenses. Workover expenses increased $0.6 million, or 460%, to $0.7 million during the three months ended September 30, 2013 from $0.1 million during the three months ended September 30, 2012. Workover expense increased due to an increased number of workovers performed during the three months ended September 30, 2013 compared to the three months ended September 30, 2012, as the Company focused on workovers to increase production from existing wells. Management has initiated plans to enhance production volumes through increased workovers, drilling vertical in-fill wells as well as exploring alternative completion and workover methods as a strategy to stabilize production from existing producing oil and gas properties.  This strategy includes increased workover activity on an accelerated time frame at least partially because of the  efforts of Kinder Morgan, Inc. to enhance their recently purchased mid stream component which serves the majority of our properties.  We anticipate that this strategy will continue well into the future in order to maximize recovery from mature properties, and we expect workover cost to continue at this increased rate for the near term to coordinate with the natural decline rate of our hydrocarbon production.

Production taxes. Production taxes increased $0.4 million, or 213%, to $0.6 million during the three months ended September 30, 2013 from $0.2 million during the three months ended September 30, 2012. The increase was due to lower production tax incentives, combined with increased revenue base from acquisitions and higher realized prices, in the 2013 period. Oklahoma production tax incentives lessen over time from first production and thus the decline in production tax incentives is attributable to the maturation of our producing properties and not any change in tax incentive policy.

General and administrative expenses. General and administrative expense decreased $1.1 million, or 46%, to $1.4 million during the three months ended September 30, 2013 from $2.5 million during the three months ended September 30, 2012. The decrease in general and administrative expense was related to zero equity-based compensation incurred in the three months ended September 30, 2013, compared to $1.1 million incurred in the three months ended September 30, 2012. 

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $1.5 million, or 44%, to $4.9 million during the three months ended September 30, 2013 from $3.4 million during the three months ended September 30, 2012. The increase was due to a higher full cost amortization base resulting from to the acquisitions completed in 2013.

Interest expense. Interest expense decreased $0.2 million, or 21%, to $0.6 million during the three months ended September 30, 2013 from $0.8 million during the three months ended September 30, 2012. The decrease is due to lower outstanding amounts borrowed on the credit facility in the 2013 period.

Losses from derivatives. Losses from derivatives were $3.5 million during the three months ended September 30, 2013 compared to losses of $1.5 million during the three months ended September 30, 2012. This was primarily the result of commodity contract prices rising during the third quarter of 2013.

Net loss. The Partnership recorded a net loss of $2.0 million during the three months ended September 30, 2013 compared to a net loss of $0.8 million during the three months ended September 30, 2012. The net loss is due to factors set forth above as well as derivative losses of $3.5 million recorded during the third quarter of 2013. 

 Results of Operations — Nine Months Ended September 30, 2013 and 2012    

Oil, Natural Gas & Natural Gas Liquids Revenues. Revenues from oil and natural gas operations were approximately $32.4 million for the nine months ended September 30, 2013, an increase of $6.0 million, or 23%, compared to the nine months ended September 30, 2012. Of the total revenues generated during the nine months ended September 30, 2013, approximately 63% were generated through natural gas liquids sales, approximately 22% 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 natural gas properties and higher realized commodity prices 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 $95.43 per Bbl during the nine months ended September 30, 2013, an increase of 2% from $93.14 per Bbl during the nine months ended September 30, 2012; 

●  total oil production was 51,124 Bbls for the nine months ended September 30, 2013, an increase of 9% from 46,931 Bbls for the nine months ended September 30, 2012; 

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●  the average realized natural gas price was $3.59 per Mcf during the nine months ended September 30, 2013, an increase of 47% from $2.44 per Mcf during the nine months ended September 30, 2012; 

●  total natural gas production was 1,955,786 Mcf for the nine months ended September 30, 2013, an increase of 14% from 1,710,243 Mcf for the nine months ended September 30, 2012; 

●  the average realized natural gas liquids price was $34.89 per Bbl during the nine months ended September 30, 2013, an increase of 5% from $33.37 per Bbl during the nine months ended September 30, 2012; and 

●  total natural gas liquids production was 588,431 Bbls for the nine months ended September 30, 2013, an increase of 10% from 536,356 Bbls for the nine months ended September 30, 2012. 

Lease operating expenses. Lease operating expense increased $2.3 million, or 61% to $6.0 million during the nine months ended September 30, 2013 from $3.7 million during the nine months ended September 30, 2012. Lease operating expenses increased due to the acquisitions of oil and natural gas properties completed in 2013.

Workover expenses. Workover expenses increased $1.6 million, or 155%, to $2.6 million during the nine months ended September 30, 2013 from $1.0 million during the nine months ended September 30, 2012. Workover expenses increased due to an increased number of workovers performed during the nine months ended September 30, 2013 compared to the nine months ended September 30, 2012, as the Company focused on workovers to increase production from existing wells.

Production taxes. Production taxes increased $1.2 million, or 141%, to $2.0 million during the nine months ended September 30, 2013 from $0.8 million during the nine months ended September 30, 2012. The increase was due to tax adjustments from prior periods, increased revenue base from acquisitions and higher realized prices, and fewer production tax incentives in the 2013 period. 

General and administrative expenses. General and administrative expense increased $0.5 million, or 5%, to $11.5 million during the nine months ended September 30, 2013 from $11.0 million during the nine months ended September 30, 2012. The increase in general and administrative expense was primarily related to higher equity-based compensation expenses incurred in the 2013 period in the amount of $7.7 million compared to $7.4 million in the 2012 period.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense increased $0.6 million, or 6%, to $11.7 million during the nine months ended September 30, 2013 from $11.1 million during the nine months ended September 30, 2012. The increase was due to a higher full cost amortization base resulting from the acquisitions completed in 2013.

Interest expense. Interest expense increased $0.8 million, or 33%, to $3.2 million during the nine months ended September 30, 2013 from $2.4 million during the nine months ended September 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 in the 2012 period, partially offset by lower outstanding amounts borrowed on the credit facility in the 2013 period.

Gains and losses from derivatives. Losses from derivatives were $2.6 million during the nine months ended September 30, 2013 compared to gains of $6.0 million during the nine months ended September 30, 2012. This was primarily the result of prices of natural gas prices falling during the second quarter of 2012 and commodity contract prices rising in the third quarter of 2013.

Net Income. The Partnership recorded net income of $4.8 million during the nine months ended September 30, 2013 compared to net income of $2.0 million during the nine months ended September 30, 2012. Among other things, a significant contributing factor is 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 nine months ended September 30, 2013.

Cash Flow – Nine months Ended September 30, 2013 and 2012 

The Partnership recorded cash flows provided by operations of $9.7 million during the nine months ended September 30, 2013 compared to $22.7 million during the nine months ended September 30, 2012. Cash flows provided by operations in the nine months ended September 30, 2013 were primarily impacted by $7.0 million of accounts receivable being distributed immediately prior to the initial public offering and higher increases in net operating assets for the nine months ended September 30, 2013.

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Cash flows used in investing activities were $34.2 million during the nine months ended September 30, 2013 compared to $9.2 million during the nine months ended September 30, 2012. Cash flows from investing activities in the 2013 period primarily reflect oil and natural gas property acquisitions and development activities.

Cash flows provided by financing activities were $24.8 million during the nine months ended September 30, 2013 compared to cash flows used in financing activities of $13.6 million during the nine months ended September 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. 

Adjusted EBITDA 

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss).

 

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(in thousands)
Adjusted EBITDA Reconciliation to Net Income (Loss):
Net income (loss)	$	(1,986	)	$	(799	)	$	4,768		$	2,014
Unrealized (gain) loss on derivatives		2,916			6,316			1,719			(889	)
Non-cash compensation expense		-			1,108			7,738			7,405
Accretion expense		59			29			145			86
Interest expense		654			824			3,220			2,422
Depreciation, depletion and amortization		4,913			3,409			11,686			11,052
Income tax expense (benefit)		-			(562	)		(12,126	)		1,166
Adjusted EBITDA	$	6,556		$	10,325		$	17,150		$	23,256

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

Our management believes Adjusted EBITDA, a non-GAAP financial measure, is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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 issue additional equity or debt securities, as needed, to finance our capital expenditures. 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.

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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 naturally over time and because we own a limited amount of undeveloped properties, we may need to acquire oil and natural gas properties 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.

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, so as 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.

As described in Note 11 to the unaudited financial statements included in this Form 10-Q, we completed the acquisition of a pressure-testing and tool rental business on November 12, 2013. We are still in the process of evaluating the estimated annual maintenance capital expenditures associated with the acquired business, and our estimate of maintenance capital expenditures for the year ending December 31, 2013 in the preceding paragraph does not include any maintenance capital expenditures related to the acquired 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.

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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, senior secured revolving credit facility. 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 initial public offering, 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, which we subsequently repaid in full.

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.

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 September 30, 2013, we had approximately $67.5 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 there from, 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 September 30, 2013, we were in compliance with all covenants of the revolving credit agreement.

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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. 

On October 29, 2013, the Partnership entered into the Third Amendment to its Credit Agreement. The Third Amendment (i) added a lender under the Credit Agreement, and (ii) increased the Partnership’s borrowing base under the Credit Agreement from $75 million to $87.5 million.

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 December 31, 2012 reserve report (which does not include production attributable to acquisitions completed during the year to date). 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 initial public 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 September 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 nine months ended September 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.

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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.

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ITEM 4.       CONTROLS AND PROCEDURES 

Evaluation of Disclosure Controls and Procedures 

Our management, under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our audit committee, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 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 September 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 September 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.

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PART II – OTHER INFORMATION 

Item 1.         Legal Proceedings 

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

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. 

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Item 6.          Exhibits 

Exhibit Number		Description
2.1		Contribution Agreement, dated as of October 4, 2013, by and between New Source Energy Partners L.P. and Scintilla (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on October 10, 2013).
3.1	—	Certificate of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.1 of 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 the Partnership’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 by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 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	—	Third Amendment to Credit Agreement, dated as of October 29, 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 party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 4, 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.

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

SIGNATURES

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

32

EXHIBIT INDEX

Exhibit Number		Description
2.1		Contribution Agreement, dated as of October 4, 2013, by and between New Source Energy Partners L.P. and Scintilla (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on October 10, 2013).
3.1	—	Certificate of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.1 of 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 the Partnership’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 by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 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	—	Third Amendment to Credit Agreement, dated as of October 29, 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 party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 4, 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.

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.

33

EX-31

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

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

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Kristian B. Kos, certify that:

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

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

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

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

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

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

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

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

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

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

Date: November 14, 2013                         

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

EX-31

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

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

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Richard D. Finley, certify that:

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

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

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

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

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

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

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

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

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

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

Date: November 14, 2013                         

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

EX-32

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

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

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

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

Date: November 14, 2013                         

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

Date: November 14, 2013                         

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

XML

Note 11 - Subsequent Events

9 Months Ended

Sep. 30, 2013

Subsequent Events [Abstract]

Subsequent Events [Text Block]

11.  Subsequent Events 

On October 4, 2013, the Partnership acquired certain producing and undeveloped oil and gas properties in the Southern Dome field from Scintilla for total consideration of $13.6 million consisting of $5.0 million in cash and 414,045 common units, valued at $20.79 per unit or an aggregate of $8.6 million, that were delivered in November.

On October 21, 2013, our general partner’s board of directors approved a cash distribution of $0.575 per unit payable on November 15, 2013 to unitholders of record on November 1, 2013.  

On October 29, 2013, the Partnership entered into a Third Amendment to its Credit Agreement (the “Third Amendment”). The Third Amendment (i) added a lender under the Credit Agreement, and (ii) increased the Partnership’s borrowing base under the Credit Agreement from $75 million to $87.5 million.

On November 12, 2013, the Partnership acquired the partnership interests in MCE, LP from its current owners (the “Contributors”) for approximately $43.6 million in total initial consideration to be paid in approximately $3.8 million in cash and 1,847,265 NSLP common units, valued using a volume weighted average trading price for the period between August 21, 2013 and November 11, 2013 of $21.55 per common unit. MCE, LP is an oilfield services company that specializes in increasing efficiencies and safety in drilling and completion processes. MCE, LP is considered to be a related party of the Partnership as the Chief Executive Officer of the Partnership, who is also the majority owner of New Source Energy GP, LLC, is one of the Contributors.

The Contributors retained 100 Class B Units in MCE, LP, which entitle them to incentive distributions of cash distributed by MCE, LP on its partnership interests above specified thresholds, up to a maximum of 50% at the highest level of distributions.

        In addition to the initial consideration, the Contributors are entitled to receive an earn out payment on May 1, 2015. Any earn out payment will be calculated based on a specified multiple of the annualized EBITDA generated by MCE, LP for the nine months ended March 31, 2015 less certain adjustments and will be satisfied using the Partnership’s common units, valued using a trailing twenty-day volume weighted average trading price as of three trading days prior to the issuance of such common units.

XML

Condensed Statements of Operations (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
REVENUES
Oil sales	$ 2,044	$ 1,390	$ 4,879	$ 4,371
Natural gas sales	2,582	1,608	7,031	4,177
Natural gas liquids sales	7,805	5,264	20,530	17,900
Total revenues	12,431	8,262	32,440	26,448
OPERATING COSTS AND EXPENSES
Oil and natural gas production expenses	3,428	1,133	8,702	4,789
Oil and natural gas production taxes	557	178	1,996	829
General and administrative	1,353	2,504	11,452	10,956
Depreciation, depletion and amortization	4,913	3,409	11,686	11,052
Accretion expense	59	29	145	86
Total operating costs and expenses	10,310	7,253	33,981	27,712
Operating income (loss)	2,121	1,009	(1,541)	(1,264)
OTHER INCOME (EXPENSE)
Interest expense	(654)	(824)	(3,220)	(2,422)
Gain (loss) from derivatives, net	(3,453)	(1,546)	(2,597)	6,866
Income (loss) before income taxes	(1,986)	(1,361)	(7,358)	3,180
Income tax benefit (expense)		562	12,126	(1,166)
Net income (loss)	(1,986)	(799)	4,768	2,014
ALLOCATION OF NET INCOME (LOSS) FOR THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013:
Net income			4,768
Net income prior to purchase of properties from New Source Energy on February 13, 2013			5,303
Net loss subsequent to purchase of properties from New Source Energy on February 13, 2013			(535)
Net income per common unit (in Dollars per share)	$ (0.22)		$ (0.01)
General Partnership Units [Member]
OTHER INCOME (EXPENSE)
Net income (loss)	(34)
ALLOCATION OF NET INCOME (LOSS) FOR THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013:
Net loss subsequent to purchase of properties from New Source Energy on February 13, 2013			(29)
Net income per common unit (in Dollars per share)	$ (0.22)
Net loss allocable to general partner for the three months ended September 30, 2013	(34)
Subordinated Units [Member]
OTHER INCOME (EXPENSE)
Net income (loss)	(479)
ALLOCATION OF NET INCOME (LOSS) FOR THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013:
Net loss subsequent to purchase of properties from New Source Energy on February 13, 2013			(430)
Net income per common unit (in Dollars per share)	$ (0.22)
Net loss allocable to subordinated units for the three months ended September 30, 2013	(479)
Common Units [Member]
OTHER INCOME (EXPENSE)
Net income (loss)	(1,473)
ALLOCATION OF NET INCOME (LOSS) FOR THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2013:
Net loss subsequent to purchase of properties from New Source Energy on February 13, 2013			(76)
Net income per common unit (in Dollars per share)	$ (0.22)
Net loss allocable to common units for the three months ended September 30, 2013	$ (1,473)

XML

Note 4 - Fair Value Measurements

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Fair Value, Measurement Inputs, Disclosure [Text Block]

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 business combinations. New assets measured at fair value during the nine months ended September 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 other acquisitions of certain oil and natural gas properties in exchange for an aggregate of $16.2 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 $67.5 million as of September 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. 

XML

Note 1 - Summary of Significant Accounting Policies (Details) - Basic and Diluted Earnings Per Unit Computations (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		8 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012
Note 1 - Summary of Significant Accounting Policies (Details) - Basic and Diluted Earnings Per Unit Computations [Line Items]
Net loss (in thousands) (in Dollars)	$ (1,986)	$ (799)	$ (535)	$ 4,768	$ 2,014
Basic and diluted loss per unit (in Dollars per share)	$ (0.22)			$ (0.01)
Common Units [Member]
Note 1 - Summary of Significant Accounting Policies (Details) - Basic and Diluted Earnings Per Unit Computations [Line Items]
Net loss (in thousands) (in Dollars)	(1,473)		(76)
Weighted average units outstanding	6,773,500		6,480,439
Basic and diluted loss per unit (in Dollars per share)	$ (0.22)		$ (0.01)
Subordinated Units [Member]
Note 1 - Summary of Significant Accounting Policies (Details) - Basic and Diluted Earnings Per Unit Computations [Line Items]
Net loss (in thousands) (in Dollars)	(479)		(430)
Weighted average units outstanding	2,205,000		2,205,000
Basic and diluted loss per unit (in Dollars per share)	$ (0.22)		$ (0.20)
General Partnership Units [Member]
Note 1 - Summary of Significant Accounting Policies (Details) - Basic and Diluted Earnings Per Unit Computations [Line Items]
Net loss (in thousands) (in Dollars)	$ (34)		$ (29)
Weighted average units outstanding	155,102		154,503
Basic and diluted loss per unit (in Dollars per share)	$ (0.22)		$ (0.19)

XML

Accounting Policies, by Policy (Policies)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

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.

Basis of Presentation 

The accompanying unaudited condensed financial statements present the financial position of the Partnership at September 30, 2013 and December 31, 2012 and the Partnership’s results of operations and cash flows for the nine months ended September 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 nine months ended September 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.

Use of Estimates, Policy [Policy Text Block]

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.

Property, Plant and Equipment, Policy [Policy Text Block]

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 internal 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 nine months ended September 30, 2013 or 2012.

Earnings Per Share, Policy [Policy Text Block]

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 September 30, 2013 were computed using the following components:

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Note 7 - Equity-Based Compensation (Details) - Equity-Based Compensation Expense (USD $) In Thousands, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Note 7 - Equity-Based Compensation (Details) - Equity-Based Compensation Expense [Line Items]
Total equity-based compensation	$ 1,108	$ 7,738	$ 7,405
New Source Energy [Member]
Note 7 - Equity-Based Compensation (Details) - Equity-Based Compensation Expense [Line Items]
Equity-based compensation allocated from New Source Energy	$ 1,108	$ 388	$ 7,405

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Note 4 - Fair Value Measurements (Details) (USD $)	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012
Note 4 - Fair Value Measurements (Details) [Line Items]
Stock Issued During Period, Shares, Purchase of Assets (in Shares)	1,400,000
Stock Issued During Period, Value, Purchase of Assets	$ 28,000,000
Payments for Purchase of Other Assets	16,200,000
Line of Credit Facility, Amount Outstanding	$ 67,500,000	$ 68,000,000
Minimum [Member]
Note 4 - Fair Value Measurements (Details) [Line Items]
Fair Value Inputs, Discount Rate	8.00%
Maximum [Member]
Note 4 - Fair Value Measurements (Details) [Line Items]
Fair Value Inputs, Discount Rate	15.00%

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Note 3 - Credit Agreement (Details) (USD $)	0 Months Ended	9 Months Ended
	Feb. 12, 2013	Sep. 30, 2013	Jun. 25, 2013	Feb. 28, 2013	Dec. 31, 2012
Note 3 - Credit Agreement (Details) [Line Items]
Line of Credit Facility, Current Borrowing Capacity (in Dollars)				$ 60,000,000
Line of Credit Facility, Maximum Borrowing Capacity (in Dollars)		75,000,000	75,000,000	150,000,000
Other Notes Payable (in Dollars)	25,000,000
Debt Instrument, Basis Spread on Variable Rate		3.31%
Line of Credit Facility, Commitment Fee Percentage	0.50%
Line of Credit Facility, Amount Outstanding (in Dollars)		67,500,000			68,000,000
Line of Credit Facility, Remaining Borrowing Capacity (in Dollars)		$ 7,500,000
Federal Funds Rate [Member]
Note 3 - Credit Agreement (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
London Interbank Offered Rate (LIBOR) [Member]
Note 3 - Credit Agreement (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Note 3 - Credit Agreement (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
Minimum [Member] | Base Rate [Member]
Note 3 - Credit Agreement (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Note 3 - Credit Agreement (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.25%
Maximum [Member] | Base Rate [Member]
Note 3 - Credit Agreement (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.25%

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Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Dec. 31, 2011
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	$ (514)
Current asset	443		25
Long-term asset	837
Current liability	(1,556)		(47)
Long-term liability	(238)
Total net financial assets (liabilities)	(514)
Oil and Natural Gas Swaps [Member] | Fair Value, Inputs, Level 2 [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	451
Oil and Natural Gas Swaps [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	451
Natural Gas Liquid Swaps [Member] | Fair Value, Inputs, Level 3 [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	(1,602)
Natural Gas Liquid Swaps [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	(1,602)
Oil, Natural Gas and Liquid Options [Member] | Fair Value, Inputs, Level 3 [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	637
Oil, Natural Gas and Liquid Options [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	637
Fair Value, Inputs, Level 2 [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	451
Current asset	279
Long-term asset	364
Current liability	(192)
Total net financial assets (liabilities)	451
Fair Value, Inputs, Level 3 [Member]
Note 5 - Derivative Contracts (Details) - Derivative Assets and Liabilities at Fair Value [Line Items]
Derivatives, Fair Value	(965)	1,866	(112)	(102)	6,007	(1,198)
Current asset	164
Long-term asset	473
Current liability	(1,364)
Long-term liability	(238)
Total net financial assets (liabilities)	$ (965)

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Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) - Allocation of Purchase Price to Fair Value of Acquired Assets and Liabilities Assumed (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
W.K. Chernicky, LLC [Member]
Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) - Allocation of Purchase Price to Fair Value of Acquired Assets and Liabilities Assumed [Line Items]
Proved oil and natural gas properties	$ 29,316
Future abandonment costs	(1,333)
Fair value of net assets acquired	27,983
NSEC [Member]
Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) - Allocation of Purchase Price to Fair Value of Acquired Assets and Liabilities Assumed [Line Items]
Proved oil and natural gas properties	8,166
Future abandonment costs	(19)
Fair value of net assets acquired	8,147
Scintilla, LLC [Member]
Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) - Allocation of Purchase Price to Fair Value of Acquired Assets and Liabilities Assumed [Line Items]
Proved oil and natural gas properties	4,866
Future abandonment costs	(8)
Fair value of net assets acquired	4,858
Orion Exploration Partners, LLC and Orion Exploration LLC [Member]
Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) - Allocation of Purchase Price to Fair Value of Acquired Assets and Liabilities Assumed [Line Items]
Proved oil and natural gas properties	3,230
Future abandonment costs	(24)
Fair value of net assets acquired	$ 3,206

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Note 5 - Derivative Contracts (Details) - Commodity Derivative Positions Oil Swaps (Oil Swaps [Member])	9 Months Ended
	Sep. 30, 2013 bbl
October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Volumes (Bbls)	8,323
Fixed Price per Bbl (in Dollars per Barrel (of Oil))	93.05
2014 [Member]
Derivative [Line Items]
Volumes (Bbls)	17,324
Fixed Price per Bbl (in Dollars per Barrel (of Oil))	90.20
2015 [Member]
Derivative [Line Items]
Volumes (Bbls)	39,411
Fixed Price per Bbl (in Dollars per Barrel (of Oil))	88.90
2016 [Member]
Derivative [Line Items]
Volumes (Bbls)	36,658
Fixed Price per Bbl (in Dollars per Barrel (of Oil))	86.00

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Note 9 - General and Administrative Expenses (Details) (USD $)	2 Months Ended	9 Months Ended
	Mar. 31, 2013	Sep. 30, 2013
General And Administrative Expenses [Abstract]
Service Management Costs		$ 675,000
Prorated Fee	$ 352,500

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Note 2 - Related Party Transactions (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Related Party Transactions [Abstract]
Due to Related Parties	$ 400,000
Due to Related Parties, Current	100,000
Due to Related Parties, Noncurrent	$ 283,000	$ 345,000

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Condensed Statements of Cash Flows (Unaudited) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$ 4,768	$ 2,014
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	11,686	11,052
Write off of loan fees due to debt refinancing	1,436
Equity-based compensation	7,738	7,405
Deferred income tax expense (benefit)	(12,023)	947
Amortization of loan fees	358	453
Accretion expense	145	86
Unrealized gain (loss) on derivatives, net	1,719	(889)
Payments for derivative option premiums	(1,334)
Changes in operating assets and liabilities:
Oil and natural gas sales receivable	(9,673)	1,276
Other current assets	(160)
Accounts payable	5,173	475
Accrued liabilities	(50)	(118)
Income taxes payable	(103)	48
Net cash provided by operating activities	9,680	22,749
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for oil and natural gas properties and equipment	(34,218)	(9,175)
Net cash used in investing activities	(34,218)	(9,175)
CASH FLOWS FROM FINANCING ACTIVITIES
Payments on long-term debt	(95,000)	(3,500)
Payments for deferred loan costs	(1,762)	(65)
Proceeds from sales of common units, net of offering costs	77,880	(492)
Proceeds from borrowings on long-term debt	69,500	3,000
Distribution to unitholders	(7,527)
Distribution to parent	(18,295)	(12,517)
Net cash provided by (used in) financing activities	24,796	(13,574)
Net change in cash and cash equivalents	258	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	258	0
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest expense	1,476	2,087
NON-CASH INVESTING AND FINANCING ACTIVITIES
Capitalized asset retirement obligation	1,403	26
Decrease in accrued capital expenditures	(258)	(478)
Income taxes assumed by parent		172
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)

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Note 2 - Related Party Transactions

9 Months Ended

Sep. 30, 2013

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

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 September 30, 2013, of which $0.1 million 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.

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Note 5 - Derivative Contracts

9 Months Ended

Sep. 30, 2013

Disclosure Text Block [Abstract]

Derivatives and Fair Value [Text Block]

 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 September 30, 2013 were as follows:

Oil put options: 

Year	Volumes (Bbls)		Floor Price
October 1, - December 31, 2013		1,209	$	80.00
2014		26,403	$	80.00

Natural gas put options: 

Year	Volumes (MMBtu)		Floor Price
October 1, - December 31, 2013		79,985	$	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
October 1, - December 31, 2013		13,862	$	28.65
2014		63,409	$	28.66

Oil swaps: 

Year	Volumes (Bbls)		Fixed Price per Bbl
October 1, - December 31, 2013		8,323	$	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
October 1, - December 31, 2013		387,288	$	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
October 1, - December 31, 2013		153,355	$	35.42	$34.72	-	$40.71
2014		541,835	$	34.94	$34.60	-	$39.39

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 September 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	$	-	$	451		$	-		$	451
Natural gas liquids swaps		-		-			(1,602	)		(1,602	)
Oil, natural gas and liquids put options		-		-			637			637
Total net financial assets (liabilities)	$	-	$	451		$	(965	)	$	(514	)
Current asset	$	-	$	279		$	164		$	443
Long-term asset		-		364			473			837
Current liability		-		(192	)		(1,364	)		(1,556	)
Long-term liability		-		-			(238	)		(238	)
Total net financial assets (liabilities)	$	-	$	451		$	(965	)	$	(514	)

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						Significant Unobservable
	Inputs (Level 3)						Inputs (Level 3)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Beginning balance	$	1,866		$	6,007		$	(112	)	$	(1,198	)
Gains (losses)		(3,277	)		(1,348	)		(1,522	)		7,063
Settlements paid (received)		446			(4,761	)		669			(5,967	)
Ending balance	$	(965	)	$	(102	)	$	(965	)	$	(102	)
Losses included in earnings related to derivatives still held as of September 30, 2013 and 2012	$	(2,677	)	$	(102	)	$	(884	)	$	(102	)

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Note 3 - Credit Agreement

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

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, senior secured revolving credit facility. 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 is 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 3.31% per annum at September 30, 2013. As of September 30, 2013, the Partnership had $67.5 million outstanding under the Credit Agreement and, as a result, had $7.5 million of available borrowing capacity. The Partnership was in compliance with all covenants of the Credit Agreement as of September 30, 2013. 

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Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) - Unaudited Pro Forma Results of Operations as Though the Acquisition (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Unaudited Pro Forma Results of Operations as Though the Acquisition [Abstract]
Revenues	$ 12,494	$ 11,104	$ 35,516	$ 35,191
Net income (loss)	$ (1,998)	$ (3,706)	$ 5,650	$ 2,797

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Note 5 - Derivative Contracts (Details) - Commodity Derivative Positions Oil Options (Oil Options [Member])	9 Months Ended
	Sep. 30, 2013 bbl
October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Volumes (Bbls)	1,209
Floor Price (in Dollars per Barrel (of Oil))	80.00
2014 [Member]
Derivative [Line Items]
Volumes (Bbls)	26,403
Floor Price (in Dollars per Barrel (of Oil))	80.00

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Note 5 - Derivative Contracts (Details) - Commodity Derivative Positions Natural Gas Swaps (Natural Gas Swaps [Member])	9 Months Ended
	Sep. 30, 2013 MMBTU
October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	387,288
Avg Price per MMBtu	3.66
2014 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	1,224,147
Avg Price per MMBtu	4.09
Range	4.09
2015 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	800,573
Avg Price per MMBtu	4.25
Range	4.25
2016 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	629,301
Avg Price per MMBtu	4.37
Range	4.37
Minimum [Member] | October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Range	3.60
Maximum [Member] | October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Range	3.69

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Note 7 - Equity-Based Compensation (Details)	0 Months Ended	12 Months Ended
	Feb. 12, 2013	Feb. 12, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock Issued During Period, Shares, Restricted Stock Award, Gross		367,500
Investment Owned, Restricted, Carrying Value Per Unit at Date of Balance Sheet (in Dollars per Item)	20.00

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Note 11 - Subsequent Events (Details) (USD $)	9 Months Ended				0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Jun. 25, 2013	Feb. 28, 2013	Oct. 04, 2013 Subsequent Event [Member] Scintilla, LLC [Member]	Nov. 12, 2013 Subsequent Event [Member] MCE, LP [Member]	Oct. 21, 2013 Subsequent Event [Member]	Oct. 29, 2013 Subsequent Event [Member]
Note 11 - Subsequent Events (Details) [Line Items]
Business Combination, Consideration Transferred					$ 13,600,000	$ 43,600,000
Payments to Acquire Oil and Gas Property	34,218,000	9,175,000			5,000,000
Stock Issued During Period, Shares, Purchase of Assets (in Shares)	1,400,000				414,045
Stock Issued During Period, Value Per Share, Purchase Of Assets (in Dollars per share)					$ 20.79
Stock Issued During Period, Value, Purchase of Assets	28,000,000				8,600,000
Distribution Made to Limited Partner, Distributions Declared, Per Unit (in Dollars per share)							$ 0.575
Line of Credit Facility, Maximum Borrowing Capacity	75,000,000		75,000,000	150,000,000				87,500,000
Payments to Acquire Businesses, Gross						$ 3,800,000
Partners' Capital Account, Units, Acquisitions (in Shares)						1,847,265
Sale of Stock, Price Per Share (in Dollars per share)						$ 21.55
Business Combination, Shares Retained by Contributers (in Shares)						100
Maximum Level of Incentive Distribution						50.00%

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Condensed Balance Sheets (Unaudited) (Parentheticals)	Sep. 30, 2013
Common units outstanding (in Shares)	6,773,500
Subordinated units outstanding (in Shares)	2,205,000
General partner's capital units outstanding (in Shares)	155,102

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Note 8 - Acquisition of Properties from New Source Energy and Other Parties

9 Months Ended

Sep. 30, 2013

Disclosure Text Block Supplement [Abstract]

Mergers, Acquisitions and Dispositions Disclosures [Text Block]

 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 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 $8.0 million in cash, after purchase price adjustments, 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

On July 23, 2013, the Partnership completed an acquisition of certain producing and undeveloped oil and gas properties in the Golden Lane field in Oklahoma from Scintilla for $5.0 million in cash, after purchase price adjustments, which approximates fair value based on future expected cash flow of the estimated reserves of the properties acquired. The acquisition closed on July 23, 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	$	4,866
Future abandonment costs		(8	)
Fair value of net assets acquired	$	4,858

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 $3.0 million in cash, after purchase price adjustments,which approximates fair value based on future expected cash flow of the estimated reserves of the properties acquired. The acquisition closed on July 25, 2013, with an effective date of June 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	$	3,230
Future abandonment costs		(24	)
Fair value of net assets acquired	$	3,206

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 September 30,						Nine months ended September 30,
	2013			2012			2013		2012
	(in thousands)
Revenues	$	12,494		$	11,104		$	35,516	$	35,191
Net income (loss)	$	(1,998	)	$	(3,706	)	$	5,650	$	2,797

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 September 30, 2013		Nine months ended September 30, 2013
	(in thousands)
Revenues	$	4,197	$	6,974
Excess of revenues over direct operating expenses	$	2,180	$	3,350

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Statement of Partners's Capital (Unaudited) (USD $) In Thousands	Subordinated Note Transferred to Parent [Member] Parent Net Investment [Member]	Cash Paid to Parent at Closing [Member] Parent Net Investment [Member]	Distribution of Accounts Receivable to Parent [Member] Parent Net Investment [Member]	Accounts Payable Assumed by Parent [Member] Parent Net Investment [Member]	Oil and Gas Properties Received for Unit Issuance [Member] Parent Net Investment [Member]	Oil and Gas Properties Received for Unit Issuance [Member] Common Units [Member]	Oil and Gas Properties Received for Unit Issuance [Member] Subordinated Units [Member]	Oil and Gas Properties Received for Unit Issuance [Member] General Partnership Units [Member]	Oil and Gas Properties Received for Unit Issuance [Member]	Parent Net Investment [Member]	Common Units [Member]	Subordinated Units [Member]	General Partnership Units [Member]	Total
Balance at Dec. 31, 2012										$ 15,975
Net Income										5,303
Allocated equity-based compensation of parent										388
Distribution										(2,495)
Increase (Decrease) Partner's Capital	(25,000)	(15,800)	(7,014)	1,742
Balance at Feb. 12, 2013
Balance at Dec. 31, 2012														15,975
Net Income														4,768
Distribution											(5,582)	(1,818)	(127)	(7,527)
Balance at Sep. 30, 2013											98,934	(20,595)	(1,404)	76,935
Balance (in Shares) at Sep. 30, 2013											6,773,500	2,205,000	155,102
Balance at Feb. 12, 2013
Net Income											(76)	(430)	(29)	(535)
Purchase of oil and natural gas properties from New Source Energy in exchange for units					26,901	(7,306)	(18,347)	(1,248)	(26,901)
Purchase of oil and natural gas properties from New Source Energy in exchange for units (in Shares)						777,500	2,205,000	150,000
Proceeds from equity offering, net of offering costs											76,565			76,565
Proceeds from equity offering, net of offering costs (in Shares)											4,250,000
Issuance to general partner from overallotment exercised (in Shares)													5,102
Equity-based compensation											7,350			7,350
Equity-based compensation (in Shares)											367,500
Units issued in exchange for oil and natural gas properties						27,983			27,983
Units issued in exchange for oil and natural gas properties (in Shares)						1,378,500
Balance at Sep. 30, 2013											98,934	(20,595)	(1,404)	76,935
Balance (in Shares) at Sep. 30, 2013											6,773,500	2,205,000	155,102
Balance at Jun. 30, 2013
Net Income											(1,473)	(479)	(34)	(1,986)
Balance at Sep. 30, 2013											$ 98,934	$ (20,595)	$ (1,404)	$ 76,935
Balance (in Shares) at Sep. 30, 2013											6,773,500	2,205,000	155,102

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Condensed Balance Sheets (Unaudited) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current assets:
Cash	$ 258	$ 0
Oil and natural gas sales receivable	7,308	5,621
Oil and natural gas sales receivable-related parties	1,145	42
Derivative assets	443	25
Other current assets	160
Total current assets	9,314	5,688
Oil and natural gas properties, at cost, using full cost method:
Proved oil and natural gas properties	262,745	202,795
Accumulated depreciation, depletion, and amortization	(124,057)	(112,372)
Total property and equipment, net	138,688	90,423
Prepaid drilling and completion costs	4,266	1,000
Loan fees, net	1,476	1,508
Deferred offering costs		1,315
Derivative assets	837
Total assets	154,581	99,934
Current liabilities:
Accounts payable	291
Accounts payable-related parties	4,510	1,564
Accrued liabilities	209	259
Accrued income taxes		103
Derivative obligations	1,556	47
Total current liabilities	6,566	1,973
Long-term related party payables	283	345
Credit facility	67,500	68,000
Derivative obligations	238	107
Asset retirement obligation	3,059	1,510
Deferred tax liability		12,024
Total liabilities	77,646	83,959
Parent net investment	76,935	15,975
Partners' capital:
Common units (6,773,500 units outstanding at September 30, 2013)	98,934
Subordinated units (2,205,000 units outstanding at September 30, 2013)	(20,595)
General partner's capital (155,102 units outstanding at September 30, 2013)	(1,404)
Total partners' capital	76,935	15,975
Total liabilities, parent net investment and partners' capital	$ 154,581	$ 99,934

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Note 5 - Derivative Contracts (Details) - Commodity Derivative Positions Natural Gas Options (Natural Gas Options [Member])	9 Months Ended
	Sep. 30, 2013 MMBTU
October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	79,985
Floor Price	3.50
2014 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	476,309
Floor Price	3.50
2015 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	798,853
Floor Price	3.50
2016 [Member]
Derivative [Line Items]
Volumes (MMBtu) (in Millions of British Thermal Units)	930,468
Floor Price	3.50

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Note 1 - Summary of Significant Accounting Policies (Details) (USD $)	9 Months Ended						0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Mar. 12, 2013	Feb. 12, 2013	Feb. 12, 2013 IPO [Member] Common Units [Member]	Feb. 12, 2013 IPO [Member] Subordinated Units [Member]	Mar. 12, 2013 IPO [Member]	Feb. 12, 2013 IPO [Member]
Note 1 - Summary of Significant Accounting Policies (Details) [Line Items]
Stock Issued During Period, Shares, New Issues (in Shares)								4,000,000
Share Price (in Dollars per share)								$ 20.00
Proceeds from Issuance of Common Stock	$ 77,880,000	$ (492,000)						$ 74,400,000
Payments of Capital Distribution								15,800,000
Noncontrolling Interest, Ownership Percentage by Parent				50.00%
Common Stock, Shares, Issued (in Shares)					777,500		250,000
Subordinated Units Issued (in Shares)						2,205,000
Other Notes Payable (in Dollars)				25,000,000				25,000,000
Liabilities Assumed								70,000,000
Proceeds from Lines of Credit	69,500,000	3,000,000						15,000,000
Proceeds from Stock Options Exercised							$ 4,700,000
Weighted Average Working Interest			38.00%
Discount of Estimated Future Net Revenues	10.00%

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Note 10 - Commitments and Contingencies (Details) (USD $)	Sep. 30, 2013
Minimum [Member]
Note 10 - Commitments and Contingencies (Details) [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 10,000
Maximum [Member]
Note 10 - Commitments and Contingencies (Details) [Line Items]
Loss Contingency, Estimate of Possible Loss	$ 250,000

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Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) (USD $) In Millions, except Share data, unless otherwise specified	9 Months Ended	0 Months Ended			6 Months Ended	0 Months Ended
	Sep. 30, 2013	Mar. 29, 2013 New Source Energy [Member]	Mar. 29, 2013 Scintilla, LLC [Member]	Mar. 29, 2013 W.K. Chernicky, LLC [Member]	Jun. 30, 2013 NSEC [Member]	Jul. 23, 2013 Scintilla, LLC [Member]	Jul. 25, 2013 Orion Exploration Partners, LLC and Orion Exploration LLC [Member]
Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) [Line Items]
Stock Issued During Period, Shares, Acquisitions (in Shares)		348,000	976,500	54,000
Stock Issued During Period, Value, Acquisitions				$ 28
Payments for Purchase of Other Assets	$ 16.2				$ 8.0	$ 5.0	$ 3.0

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Note 5 - Derivative Contracts (Details) - Reconciliation of Changes in the Fair Value of Allocated Derivative Assets and Liabilities at Level Three (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Gains (losses)	$ (3,453)	$ (1,546)	$ (2,597)	$ 6,866
Ending balance	(514)		(514)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance	1,866	6,007	(112)	(1,198)
Gains (losses)	(3,277)	(1,348)	(1,522)	7,063
Settlements paid (received)	446	(4,761)	669	(5,967)
Ending balance	(965)	(102)	(965)	(102)
Losses included in earnings related to derivatives still held as of September 30, 2013 and 2012	$ (2,677)	$ (102)	$ (884)	$ (102)

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Note 6 - Income Taxes (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Note 6 - Income Taxes (Details) [Line Items]
Income Tax Expense (Benefit)	$ (562)	$ (12,126)	$ 1,166
Related to Change in Tax Status [Member]
Note 6 - Income Taxes (Details) [Line Items]
Income Tax Expense (Benefit)		$ (12,100)

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Note 7 - Equity-Based Compensation

9 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

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 September 30, 2013 and 2012 (in thousands):

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Total equity-based compensation	$	-	$	1,108	$	7,738	$	7,405
Equity-based compensation allocated from New Source Energy	$	-	$	1,108	$	388	$	7,405

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Note 5 - Derivative Contracts (Details) - Commodity Derivative Positions Natural Gas Liquid Options (Natural Gas Liquid Options [Member])	9 Months Ended
	Sep. 30, 2013 bbl
October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Volumes (Bbls)	13,862
Average Floor Price (in Dollars per Barrel (of Oil))	28.65
2014 [Member]
Derivative [Line Items]
Volumes (Bbls)	63,409
Average Floor Price (in Dollars per Barrel (of Oil))	28.66

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Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Details) - Amounts of Revenues and Revenues in Excess of Direct Operating Expenses Included in Statement of Operations for Acquisition (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Business Acquisition [Line Items]
Revenues	$ 12,431	$ 8,262	$ 32,440	$ 26,448
Excess of revenues over direct operating expenses	2,121	1,009	(1,541)	(1,264)
Series of Individually Immaterial Business Acquisitions [Member]
Business Acquisition [Line Items]
Revenues	4,197		6,974
Excess of revenues over direct operating expenses	$ 2,180		$ 3,350

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Note 10 - Commitments and Contingencies

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

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.

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Note 6 - Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

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.

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Note 1 - Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

 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.

Basis of Presentation 

The accompanying unaudited condensed financial statements present the financial position of the Partnership at September 30, 2013 and December 31, 2012 and the Partnership’s results of operations and cash flows for the nine months ended September 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 nine months ended September 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. 

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 internal 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 nine months ended September 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 September 30, 2013 were computed using the following components:

	Common Units			Subordinated Units			General Partner
Numerator
Net loss (in thousands)	$	(76	)	$	(430	)	$	(29	)
Denominator:
Weighted average units outstanding		6,480,439			2,205,000			154,503
Basic and diluted loss per unit	$	(0.01	)	$	(0.20	)	$	(0.19	)

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

	Common Units			Subordinated Units			General Partner
Numerator
Net loss (in thousands)	$	(1,473	)	$	(479	)	$	(34	)
Denominator:
Weighted average units outstanding		6,773,500			2,205,000			155,102
Basic and diluted loss per unit	$	(0.22	)	$	(0.22	)	$	(0.22	)

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Note 5 - Derivative Contracts (Details) - Commodity Derivative Positions Liquid Swaps (Natural Gas Liquid Swaps [Member])	9 Months Ended
	Sep. 30, 2013 bbl
October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Volumes (Bbls) (in Barrels (of Oil))	153,355
Avg Price per Bbl	35.42
2014 [Member]
Derivative [Line Items]
Volumes (Bbls) (in Barrels (of Oil))	541,835
Avg Price per Bbl	34.94
Minimum [Member] | October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Range	34.72
Minimum [Member] | 2014 [Member]
Derivative [Line Items]
Range	34.60
Maximum [Member] | October 1 - December 31, 2013 [Member]
Derivative [Line Items]
Range	40.71
Maximum [Member] | 2014 [Member]
Derivative [Line Items]
Range	39.39

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Note 1 - Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2013

Accounting Policies [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

	Common Units			Subordinated Units			General Partner
Numerator
Net loss (in thousands)	$	(76	)	$	(430	)	$	(29	)
Denominator:
Weighted average units outstanding		6,480,439			2,205,000			154,503
Basic and diluted loss per unit	$	(0.01	)	$	(0.20	)	$	(0.19	)

	Common Units			Subordinated Units			General Partner
Numerator
Net loss (in thousands)	$	(1,473	)	$	(479	)	$	(34	)
Denominator:
Weighted average units outstanding		6,773,500			2,205,000			155,102
Basic and diluted loss per unit	$	(0.22	)	$	(0.22	)	$	(0.22	)

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Note 9 - General and Administrative Expenses

9 Months Ended

Sep. 30, 2013

General And Administrative Expenses [Abstract]

General And Administrative Expenses [Text Block]

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.

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Note 8 - Acquisition of Properties from New Source Energy and Other Parties (Tables)

9 Months Ended

Sep. 30, 2013

Disclosure Text Block Supplement [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

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

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

Proved oil and natural gas properties	$	4,866
Future abandonment costs		(8	)
Fair value of net assets acquired	$	4,858

Proved oil and natural gas properties	$	3,230
Future abandonment costs		(24	)
Fair value of net assets acquired	$	3,206

Business Acquisition, Pro Forma Information [Table Text Block]

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013		2012
	(in thousands)
Revenues	$	12,494		$	11,104		$	35,516	$	35,191
Net income (loss)	$	(1,998	)	$	(3,706	)	$	5,650	$	2,797

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

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

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Note 5 - Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2013

Note 5 - Derivative Contracts (Tables) [Line Items]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

Description	Active Market for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
Oil and natural gas swaps	$	-	$	451		$	-		$	451
Natural gas liquids swaps		-		-			(1,602	)		(1,602	)
Oil, natural gas and liquids put options		-		-			637			637
Total net financial assets (liabilities)	$	-	$	451		$	(965	)	$	(514	)
Current asset	$	-	$	279		$	164		$	443
Long-term asset		-		364			473			837
Current liability		-		(192	)		(1,364	)		(1,556	)
Long-term liability		-		-			(238	)		(238	)
Total net financial assets (liabilities)	$	-	$	451		$	(965	)	$	(514	)

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]

	Significant Unobservable						Significant Unobservable
	Inputs (Level 3)						Inputs (Level 3)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2013			2012			2013			2012
Beginning balance	$	1,866		$	6,007		$	(112	)	$	(1,198	)
Gains (losses)		(3,277	)		(1,348	)		(1,522	)		7,063
Settlements paid (received)		446			(4,761	)		669			(5,967	)
Ending balance	$	(965	)	$	(102	)	$	(965	)	$	(102	)
Losses included in earnings related to derivatives still held as of September 30, 2013 and 2012	$	(2,677	)	$	(102	)	$	(884	)	$	(102	)

Oil Options [Member]

Note 5 - Derivative Contracts (Tables) [Line Items]

Schedule of Derivative Instruments [Table Text Block]

Year	Volumes (Bbls)		Floor Price
October 1, - December 31, 2013		1,209	$	80.00
2014		26,403	$	80.00

Natural Gas Options [Member]

Note 5 - Derivative Contracts (Tables) [Line Items]

Schedule of Derivative Instruments [Table Text Block]

Year	Volumes (MMBtu)		Floor Price
October 1, - December 31, 2013		79,985	$	3.50
2014		476,309	$	3.50
2015		798,853	$	3.50
2016		930,468	$	3.50

Natural Gas Liquid Options [Member]

Note 5 - Derivative Contracts (Tables) [Line Items]

Schedule of Derivative Instruments [Table Text Block]

Year	Volumes (Bbls)		Average Floor Price
October 1, - December 31, 2013		13,862	$	28.65
2014		63,409	$	28.66

Oil Swaps [Member]

Note 5 - Derivative Contracts (Tables) [Line Items]

Schedule of Derivative Instruments [Table Text Block]

Year	Volumes (Bbls)		Fixed Price per Bbl
October 1, - December 31, 2013		8,323	$	93.05
2014		17,324	$	90.20
2015		39,411	$	88.90
2016		36,658	$	86.00

Natural Gas Swaps [Member]

Note 5 - Derivative Contracts (Tables) [Line Items]

Schedule of Derivative Instruments [Table Text Block]

Year	Volumes (MMBtu)		Avg Price per MMBtu		Range
October 1, - December 31, 2013		387,288	$	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 [Member]

Note 5 - Derivative Contracts (Tables) [Line Items]

Schedule of Derivative Instruments [Table Text Block]

Year	Volumes (Bbls)		Avg Price		Range
October 1, - December 31, 2013		153,355	$	35.42	$34.72	-	$40.71
2014		541,835	$	34.94	$34.60	-	$39.39

XML

Document And Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 14, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	New Source Energy Partners L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		9,034,810
Amendment Flag	false
Entity Central Index Key	0001560443
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Sep. 30, 2013
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3

XML

Note 7 - Equity-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Compensation, Activity [Table Text Block]

	Three months ended September 30,				Nine months ended September 30,
	2013		2012		2013		2012
Total equity-based compensation	$	-	$	1,108	$	7,738	$	7,405
Equity-based compensation allocated from New Source Energy	$	-	$	1,108	$	388	$	7,405