New Source Energy Partners 10K 2012 Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

(MARK ONE)

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

For the fiscal year ended December 31, 2012

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

FOR THE TRANSITION PERIOD FROM____________TO____________.

Commission File No. 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

Securities Registered Pursuant to Section 12(b) of the Act:

Common Units Representing Limited Partner Interests	New York Stock Exchange
(Title of each class)	(Name of each exchange on which registered)

Securities Registered Pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x

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 o No x

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 during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Annual Report on Form 10-K or any amendment to this Annual Report on Form 10-K. x

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 o Accelerated filer o Non-accelerated filer þ Smaller reporting company o

(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 o No x

As of June 30, 2012, the last business day of the registrant's most recently completed second fiscal quarter, the registrant's equity was not listed on any domestic exchange or over-the-counter market. The registrant's common units began trading on the New York Stock Exchange on February 8, 2013.

As of March 29, 2013, the registrant had 6,773,500 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

TABLE OF CONTENTS

		Page

Part I.

Item 1.	Business	10
Item 1A.	Risk Factors	24
Item 2.	Properties	51
Item 3.	Legal Proceedings	56
Item 4.	Mine Safety Disclosures	57

Part II.

Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	57
Item 6.	Selected Financial Data	60
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	62
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	78
Item 8.	Financial Statements and Supplementary Data	81
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	111
Item 9A.	Controls and Procedures	111
Item 9B.	Other Information	112

Part III.

Item 10.	Directors, Executive Officers and Corporate Governance	113
Item 11.	Executive Compensation	117
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	120
Item 13.	Certain Relationships and Related Transactions, and Director Independence	121
Item 14.	Principal Accountant Fees and Services	126

Part IV.

Item 15.	Exhibits and Financial Statement Schedules	126

Emerging Growth Company Status

We are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act, or “JOBS Act.” For as long as we are an emerging growth company, unlike other public companies, we will not be required to:

provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002;

comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer;

comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise;

provide certain disclosure regarding executive compensation required of larger public companies; or

obtain shareholder approval of any golden parachute payments not previously approved.

We will cease to be an “emerging growth company” upon the earliest of:

when we have $1.0 billion or more in annual revenues;

when we have at least $700 million in market value of our common units held by non-affiliates;

when we issue more than $1.0 billion of non-convertible debt over a three-year period; or

the last day of the fiscal year following the fifth anniversary of our initial public offering.

In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following includes a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. All natural gas reserves and production reported in this Annual Report on Form 10-K are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit.

3-D seismic data: Geophysical data that depicts the subsurface strata in three dimensions.

Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

Basin: A large depression on the earth’s surface in which sediments accumulate.

Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d: One Bbl per day.

Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.

Boe/d: One Boe per day.

Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.

Completion: The process of strengthening a well hole with casing, evaluating the pressure and temperature of the formation, and then installing the proper equipment to ensure an efficient flow of oil and natural gas out of the well.

Condensate: Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

Conventional Reservoir: A reservoir in which buoyant forces keep hydrocarbons in place below a sealing caprock. Reservoir and fluid characteristics of conventional reservoirs typically permit oil or natural gas to flow readily into wellbores. The term is used to make a distinction from shale and other unconventional reservoirs, in which gas might be distributed throughout the reservoir at the basin scale, and in which buoyant forces or the influence of a water column on the location of hydrocarbons within the reservoir are not significant.

Conventional Resource Reservoir: A conventional reservoir demonstrating the characteristics defined by a resource play. Conventional resource plays are also referred to as transition zone reservoirs. The reservoir may be over or under-pressured. The conventional resource play is conducive to assembly-line operations, with upside potential to improve recoveries and efficiencies from enhanced methodologies including seismic, log interpretation, cores, drilling, completion and operations.

Development Costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves;

(ii) drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;

(iii) acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

(iv) provide improved recovery systems.

Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

The value of the products that generate revenue shall be determined at the terminal point of oil and natural gas producing activities.

Environmental Assessment: A study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.

Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Formation: A layer of rock which has distinct characteristics that differ from nearby rock.

Fracture Stimulation: A process whereby fluids mixed with proppants are injected into a wellbore under pressure to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.

Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.

Horizontal Drilling: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

MBoe: One thousand Boe.

MBoe/d: One thousand Boe per day.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million Btu.

Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage working interest.

Net Production: Production that is owned by us less royalties and production due others.

Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.

NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate and natural gas liquids.

Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.

Permeability: The measure of the ease with which fluid flows through a porous rock and is a function of interconnection between the pores.

Play: A geographic area with hydrocarbon potential.

Plugging and Abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Porosity: The ratio of the void space in a rock to the bulk volume of that rock multiplied by 100 to express in percent.

Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.

Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Realized Price: The cash market price less all expected quality, transportation and demand adjustments.

Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Resource Play: An accumulation of hydrocarbons known to exist over a large areal expanse that is believed to have a lower geological and/or commercial development risk. A resource play is a continuous hydrocarbon system over a contiguous geographical area that is regional in extent, exhibits both low exploration risk with consistent results, and predictable estimated ultimate recoveries. Performance is a function of reservoir geology, which includes variations in thickness, rock lithology, porosity, permeability, in-situ stress, minerology, and completion efficiency. Resource play reservoirs can be described using a statistical description and importantly, this statistical description changes little over time provided interference between wells is minimal. A resource play is conducive to assembly-line operations, with upside potential to improve recoveries and efficiencies from enhanced methodologies—seismic, log interpretation, cores, drilling, completion and operations.

Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.

Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.

Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.

Unconventional Reservoirs: A term used in the oil and natural gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds, or (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes to produce economic flow rates.

Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.

Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

Workover: Operations on a producing well to restore or increase production.

WTI: West Texas Intermediate.

The terms “analogous reservoir,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery,” “exploratory well,” “proved developed reserves,” “proved reserves,” “proved undeveloped reserves,” “reliable technology,” “reserves,” and “resources” are defined by the Securities and Exchange Commission (the "SEC").

NAMES OF ENTITIES

Unless we indicate otherwise, our financial, reserve and operating information in this Annual Report on Form 10-K reflects the results and financial position attributable to the Partnership Properties and is presented on a historical basis. The estimated proved reserve information for the Partnership Properties as of December 31, 2012 contained in this Annual Report on Form 10-K is based on a report prepared by Ralph E. Davis Associates, Inc., our independent reserve engineers. We refer to this report as our “reserve report.” As used in this Annual Report on Form 10-K, unless otherwise indicated, the following terms have the following meanings:

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

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

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

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

“Scintilla” refers to Scintilla, LLC, the entity from which New Source Energy acquired substantially all of its assets in August 2011, including the Partnership Properties (defined below);

“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 Annual Report on Form 10-K, the New Source Group refers to the parties (other than us) party thereto;

“Partnership Properties” or “our properties” refers to the properties, producing wells, and related oil and natural gas interests that were contributed to us by New Source Energy in connection with the initial public offering; 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.

CAUTIONARY STATEMENTS REGARDING FORWARD LOOKING STATEMENTS

The information discussed in this Annual Report on Form 10-K 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:

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 upon becoming a public company to implement and assess periodically the effectiveness of our internal control over financial reporting and the substantial costs associated with doing so;

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

environmental risks;

geographical concentration of our operations;

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

availability of borrowings under our revolving credit facility;

drilling and operating risks;

exploration and development risks;

competition in the oil and natural gas industry;

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

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

failure to meet the proposed drilling schedule on our properties;

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

drilling operations and adverse weather and environmental conditions;

limited control over non-operated properties;

reliance on a limited number of customers;

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

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

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

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

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

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

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

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

federal, state, and tribal regulations and laws;

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

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

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

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

the effect of seasonal factors;

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

further sales or issuances of common units;

our limited trading history;

costs of purchasing electricity and disposing of saltwater;

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

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

Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in “Item 1A. Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Annual Report on Form 10-K and speak only as of the date of this Annual Report on Form 10-K. 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.

PART I.

ITEM 1.

BUSINESS

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 (the “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. Average net daily production from our properties during the year ended December 31, 2012 was 3,147 Boe/d, which is comprised of 167 Bbl/d of oil, 6,225 Mcf/d of natural gas and 1,943 Bbl/d of natural gas liquids. Based on net production from our properties for the year ended December 31, 2012, the total proved reserves associated with our properties had a reserve to production ratio of 12.3 years.

As of December 31, 2012, we had 90,692 gross (32,061 net) acres, of which 6,452 gross (2,209 net) acres were undeveloped. As of December 31, 2012, we had 121 gross (27.8 net) proved undeveloped drilling locations, of which 66 gross (21.6 net) were infill drilling locations. Pursuant to a development agreement we entered into at the closing of our initial public offering (the "IPO"), our general partner determines and periodically updates our annual maintenance drilling budget, and has the right to propose which wells are drilled based on our annual maintenance drilling budget. Pursuant to our development agreement, during each of our fiscal years ending December 31, 2013 through December 31, 2016, we have agreed to maintain an average annual maintenance drilling budget of $8.2 million to drill certain of our proved undeveloped locations and maintain our producing wells. In addition to our annual maintenance drilling budget, we anticipate our general partner will annually propose additional growth capital expenditures and related drilling and development projects to grow our resources and production over time, subject to our ability to raise sufficient capital to do so, primarily through drilling additional proved undeveloped properties, increasing our working interests in wells through forced pooling and acquiring properties from both New Source Energy and third parties. Our general partner also has the ability to approve deviations from either the drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.

We believe our business relationship with the New Source Group enhances our ability to grow our production and expand our proved reserves base over time. New Source Energy owns approximately 39.2% of our limited partner interests and 5.6% of our general partner. As of December 31, 2012, New Source Energy had interests in over 34,292 gross (14,863 net) acres of undeveloped properties. After additional capital is invested, we believe that many of these properties will become suitable for us, based on our criteria that suitable properties consist of mature onshore oil and natural gas reservoirs with long-lived, predictable production profiles.

Recent Developments

Initial Public Offering of New Source Energy Partners L.P.

On February 13, 2013, we completed our IPO of 4,000,000 common units representing limited partner interests in the Partnership at $20.00 per common unit for total net proceeds of $71.6 million. Our common units are traded on the New York Stock Exchange (“NYSE”) under the symbol “NSLP.” In connection with the IPO, New Source Energy contributed to us certain properties, producing wells, and related oil and natural gas interests. In exchange, we assumed approximately $70.0 million of New Source Energy’s indebtedness that burdened the Partnership Properties, and used a portion of the IPO net proceeds to repay in full such assumed debt at the closing of the IPO. We used $0.8 million of the remaining net proceeds, together with $15.0 million of borrowings under our revolving credit facility, to make a distribution to New Source Energy as consideration (together with our issuance to New Source Energy of 777,500 common units, 2,205,000 subordinated units and a $25.0 million note payable) for the contribution by New Source Energy of the Partnership Properties and certain commodity derivative contracts. The remaining net proceeds will be used for general partnership purposes.

On March 8, 2013, the underwriters exercised in part their over-allotment option to purchase an additional 250,000 common units. We received total net proceeds from the exercise of the underwriters’ over-allotment option of $4.65 million. Upon completion of the IPO, the issuance of 367,500 common units to management and affiliates under our Long-Term Incentive Plan and the underwriters' partial exercise of their over-allotment option, we had 5,395,000 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.

Ownership of our General Partner

On March 15, 2013, the limited liability company agreement of our general partner was amended. Our general partner is currently owned 69.4% by an entity controlled by Mr. Kos, the President and Chief Executive Officer of our general partner, 25% by an entity controlled by Mr. Chernicky, the Chairman of the board of directors of our general partner, and 5.6% by New Source Energy.

Acquisition of Properties from New Source Energy and Other Parties

On March 29, 2013, we acquired certain producing and undeveloped oil and gas properties in the Golden Lane and Luther fields in Oklahoma from New Source Energy, Scintilla and W.K. Chernicky, LLC in exchange for an aggregate 1,378,500 common units. The acquired properties have estimated proved reserves as of December 31, 2012 of approximately 3.9 MMBoe.

Our Development Agreement with the New Source Group

We are party to a development agreement with the New Source Group with respect to the drilling of our proved undeveloped reserves that comprise a portion of the Partnership Properties. During each of our fiscal years ending December 31, 2013 through December 31, 2016, we have agreed to maintain an average annual maintenance drilling budget of $8.2 million to drill certain of our proved undeveloped locations and maintain our producing wells. In connection with our entry into the development agreement, we became a party to the Golden Lane Participation Agreement. For a description of the Golden Lane Participation Agreement, please read “—Material Definitive Agreements—Golden Lane Participation Agreement.”

Additionally, beginning with the first quarter of 2014 and continuing through the fourth quarter of 2016, if our average production declines below 3,200 Boe/d for any preceding four quarter period, then holders of our subordinated units will not be entitled to receive the quarterly distributions otherwise payable on our subordinated units for such quarter. We expect that any funds not distributed to holders of our subordinated units will be reserved by the board of directors of our general partner for use in growing our production.

While we have committed to establishing a maintenance drilling budget which provides that we spend an average of $8.2 million annually from 2013 through 2016 pursuant to the development agreement, we anticipate that our general partner will propose, not less than annually, additional growth capital expenditures and related drilling and development projects to grow our resources and production over time. We expect this growth to come through drilling additional proved undeveloped properties, increasing our working interests in wells through forced pooling and acquiring properties from both New Source Group and third parties. The amount and timing of these growth capital expenditures will depend on both the amount of capital we have available to fund such expenditures as well as the success of our drilling program.

Pursuant to the development agreement, our general partner, at least annually and likely more frequently, at its discretion, determines our maintenance drilling budget. Our general partner also has the right to propose which wells are drilled based on our maintenance drilling budget. Under the development agreement, New Dominion is obligated to use its commercially reasonable best efforts to (i) conduct its operations such that the Partnership’s proportionate share of capital expenses that we would consider maintenance capital under the Golden Lane Participation Agreement is equal to the annual maintenance drilling budget set by our general partner and (ii) cause the wells drilled pursuant to the Golden Lane Participation Agreement to be consistent with the maintenance drilling schedule proposed by our general partner. Our general partner also has the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.

Our Hedging Strategy

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. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so.

Our commodity derivative contracts may consist of natural gas, oil and NGL financial swaps, put options and/or collar contracts and natural gas basis financial swaps. By removing a significant portion of price volatility associated with production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in commodity prices on our cash flow from operations for those periods. However, our hedging activity may also reduce our ability to benefit from increases in commodity prices. Additionally, we intend to individually identify these non-speculative hedges as “designated hedges” for U.S. federal income tax purposes as we enter into them. For a description of our commodity derivative contracts, please read “Item 7A — Quantitative and Qualitative Disclosures about Market Risk.”

Our Relationship with the New Source Group

New Source Energy is controlled by its principal stockholder, chairman and senior geologist, David J. Chernicky. Mr. Chernicky also owns all of the membership interests in New Dominion and Scintilla. Mr. Chernicky has historically acquired oil and natural gas properties through Scintilla, and New Dominion has acted as the operator for properties held by Scintilla for over 12 years, completing and economically producing from more than 98% of all wells it has drilled in the Hunton Formation. New Source Energy acquired substantially all of its assets from Scintilla in August 2011, including the Partnership Properties. New Source Energy holds 1,125,500 common units (approximately 16.6% of all outstanding) and 2,205,000 subordinated units (100% of all outstanding), and owns 5.6% of the membership interests in our general partner.

As a result of its significant ownership interests in us we believe New Source Energy is motivated to support the successful execution of our business strategy and provides us with opportunities to pursue acquisitions that will be accretive to our unitholders. New Source Energy views our partnership as part of its growth strategy, and we believe that New Source Energy is incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. However, New Source Energy regularly evaluates acquisitions and dispositions and may elect to acquire or dispose of properties in the future without offering us the opportunity to participate in those transactions. Moreover, New Source Energy is free to act in a manner that is beneficial to its interests without regard to ours, which may include electing not to present us with future acquisition opportunities. Although we believe New Source Energy is incentivized to offer properties to us for purchase, New Source Energy has no obligation to sell or offer properties to us. If New Source Energy fails to present us with, or successfully competes against us for, acquisition opportunities, then our ability to replace or increase our estimated proved reserves may be impaired, which would adversely affect our cash flow from operations and our ability to make cash distributions to our unitholders.

Our Operations

Our operations are focused in east-central Oklahoma, specifically the Golden Lane field located in Pottawatomie, Seminole and Okfuskee Counties. Our developmental focus is on the Hunton Formation, a liquids-rich subterranean limestone reservoir. The Hunton Formation is a conventional resource reservoir extending thousands of square miles across the State of Oklahoma. Though our current production is only from the Hunton Formation, we believe the New Source Group’s specialized processes could have potential application in several other reservoirs above and below the Hunton Formation in which we may have an opportunity to acquire interests in the future, including the Cleveland, Red Fork, Caney, Mississippian and Arbuckle.

Conventional Resource Reservoirs—Hunton Formation

The Hunton Formation was deposited in a shelf carbonate environment and exhibits many of the characteristics associated with this type of environment, including but not limited to, coral reefs, major dolomitization, and hundreds of major and minor disconformities caused by sea level changes and Karst topography. The Hunton Formation is of Silurian-Devonian geological age and consists primarily of the Chimney Hill and Henryhouse subgroup. It varies in thickness from 0 to over 200 feet and can be mapped accurately from the thousands of subsurface penetrations over the last 90 years. It typically exhibits porosity that varies both vertically and laterally. Vertical permeability is generally poor owing to the many disconformities, but horizontal permeability and porosity is much greater and permeability in both directions is greatly enhanced due to many sets of naturally occurring fracture systems.

Golden Lane Field

As of December 31, 2012, our properties consisted of approximately 90,692 gross (32,061 net) acres leased or held by production with 216 gross (82.0 net) wells in production. Additionally, as of December 31, 2012, there were 121 gross (27.8 net) proved undeveloped drilling locations that target the Hunton Formation. The average cost per horizontal well drilled by the New Source Group in the Hunton Formation for the twelve months ended December 31, 2012 was $2.6 million (based upon 640-acre spacing), including drilling, completion, gathering, and infrastructure connection expenses.

Average net daily production from our properties in the Golden Lane field was 3,147 Boe/d for the year ended December 31, 2012, which is comprised of 167 Bbl/d of oil, 6,225 Mcf/d of natural gas and 1,943 Bbl/d of natural gas liquids, all of which was produced from the Hunton Formation. At December 31, 2012, we held a working interest ranging from 19% to 87% (38.0% weighted average) in 216 gross (82.0 net) wells in the Golden Lane field. Additionally, as of December 31, 2012, we had identified 121 gross (27.8 net) proved undeveloped drilling locations on our Golden Lane acreage. These proved undeveloped drilling locations include 66 gross (21.6 net) proved undeveloped drilling infill drilling locations based on 320-acre spacing, while the remaining number of such proved undeveloped drilling locations are based on 320- to 640-acre spacing. During the year ended December 31, 2012, the average cost to drill and complete these wells for the contract operator was $2.6 million.

Specialized Processes

We, through the New Source Group, use proven methods, mechanical assistance and other specialized processes to produce still-remaining reserves from conventional oil and liquids-rich resource plays previously deemed not prospective by others. Our success comes from understanding the reservoir characteristics and, in conjunction with the New Source Group, using the latest available drilling, completion, and production technology to create natural conductive flow paths that enable access to the hydrocarbons within. This advanced recovery technique makes it highly economic to produce from these reservoirs. Along with horizontal and directional drilling, high-volume, electric submersible pumps are used in our wells to reduce the hydrostatic pressure in the reservoir and pull water, gas and oil from source rock formations in a way that enables those formations to produce oil and liquids-rich natural gas. Specially designed separators installed on production pad sites separate out the water, natural gas and oil. The water is sent to permitted transportation and disposal facilities. The natural gas flows into a gathering system and then to processing plants, while the oil is transported to the nearest pipeline.

With the implementation of the New Source Group’s specialized processes, we have the ability to potentially develop a new class of large-scale reservoir systems. Other reservoirs with high water saturation have been identified in the regions in which we currently operate, and we believe they exist in many other areas in which hydrocarbons have customarily been produced. Large reservoirs previously thought to be too high in water saturation to produce potentially can be opened up to full—scale development involving the drilling and completion of hundreds of wells in a reservoir that can cover thousands of square miles.

Unlike typical oil and natural gas reservoirs, which show declining oil and gas production rates with time, this type of reservoir increases its oil and natural gas production rate over an initial period, and then, as the reservoir is depressurized, the wells assume a more typical decline curve.

Our conventional resource plays

The type of conventional resource play on which we focus is a high water saturation hydrocarbon reservoir that demonstrates characteristics of both a conventional reservoir and a resource play. The reservoir is typically made of carbonate or deltaic sand deposits. In these reservoirs, the porosity and permeability are not well connected vertically in the formation, which restricts the movement of fluid vertically through the reservoir. However, these reservoirs have good horizontal permeability and porosity that usually extends over a large area. In addition, the permeability in both directions often is enhanced by numerous naturally occurring fracture systems.

These types of reservoirs are composed of hydrocarbon accumulations in strata that have “shows” of oil, but the reservoirs typically have been deemed not prospective by others due primarily to having water saturations of 35 to 99 percent. Although the reservoir is saturated with water, there often are significant hydrocarbons present and suspended within the reservoir by the hydrostatic pressure. Conventional resource reservoirs are located around and below the conventional reservoir, though they can exist independently. This zone is a continuous hydrocarbon system over a contiguous geographical area that can be very large. Conventional resource plays are regional in extent and exhibit low risk with consistent results and predictable recoveries.

Development of our conventional resource plays

The New Source Group’s technical staff has developed geologic and engineering expertise in the areas of production phase identification, well design for horizontal drilling, strategic submersible pump placement, and product separation with disposal processes. We believe this experience helps us to understand the characteristics of, and obtain efficiencies in production from, the conventional resource plays on which we focus.

The New Source Group uses mapping and seismic workstation capabilities to manage large volumes of digital data to correlate key reservoir parameters. This allows the technical staff to process large volumes of geological and geophysical data including cores, well tests, log suites on wells, seismic, and surface variables which in turn provides us with an optimal view and analysis of critical data and minimizes misinterpretations of information.

Resource recovery relies upon exploitation of the reservoir through development versus exploration. This allows production utilizing the following steps:

understanding the reservoir characteristics through complete geological analysis, extensive log analysis, core sampling where appropriate, geophysical review and economic review;

optimally drilling the reservoir by using multiple horizontal legs to maximize exposure to the reservoir and optimize conductive flow paths to the wellbore, and drilling four 640-acre sections from one well pad; and

harvesting fluids from the reservoir by pre-installing surface infrastructure, separating the fluids into oil, condensate, natural gas liquids, natural gas, and water, and maximizing recovery through well placement to optimize the effect of wells working in concert.

The majority of the hydrocarbons remain locked in the reservoir for up to six months after a well is completed and brought online. During this time fluids in the naturally occurring fractures are vacated utilizing electric submersible pumps, allowing the hydrostatic pressure in the reservoir to be lowered, which in turn enables the hydrocarbons to expand and vacate the pores in which they are trapped. It is at this time that peak production rates, which can average over 200 Boe per day, are observed and sustained for periods typically in excess of twelve months. During the latter stages of the well life, the electric submersible pumps are replaced with beam pumps that are less expensive to operate and maintain, resulting in additional cost efficiencies.

As the formation is depressurized, the Btu content of the hydrocarbon production stream increases. Over the life of the well this creates greater volumes of condensate and NGLs per Boe produced.

The decline of saltwater volumes produced is similar to the decline of hydrocarbon production following the peak production period. This reduces operating costs over time, in turn extending the economic life of the well and maximizing the hydrocarbon recovery from the reservoir.

Our method of hydrocarbon production from conventional resource reservoirs is predicated on evaluating the optimal way to create laminar flow from the reservoir. By establishing an appropriate flow rate, the reservoir pressure drops to a point that allows for the maximum release of hydrocarbons in place. The New Source Group historically has been successful with infill drilling based on its evaluation of appropriate wellbore placement in order to create the best flow rates for reservoir drainage. In conjunction with the New Source Group, we will continuously evaluate our drilling program to select the types and spacing of wells to be drilled in order to optimize our flow rates and maximize the recovery of hydrocarbons from the Hunton reservoir. Based on our analysis to date, as of December 31, 2012, we have identified 121 gross (27.8 net) proved undeveloped drilling locations for prospective development.

Forced pooling process

Under Oklahoma law, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and natural gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may commence a “forced pooling” process. In a forced pooling action, which is common in Oklahoma, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate in an administrative proceeding that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair market value of the mineral interests in the unit is determined in the administrative proceeding by reference to market transactions involving nearby oil and natural gas rights, especially what has been paid for mineral leases in the particular drilling and spacing unit and the immediately surrounding drilling and spacing units.

Assuming the application is granted and a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair market value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair market value established and approved through the administrative hearing. The pooling order usually also addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.

The availability of forced pooling means that it normally is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Exploration and production companies in Oklahoma often negotiate to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, through the efforts of the New Source Group, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.

The New Source Group’s experience has been that very few other interest owners elect to participate in the drilling of new wells in our area of operations. The New Source Group has drilled a total of 69 wells over the three years ended December 31, 2012 in the areas of mutual interest defined by the Golden Lane Participation Agreement through successful forced pooling efforts. On average, the collective working interest of third party owners of mineral rights in these drilling units who have elected to participate in these wells (excluding participation by the other parties to the Golden Lane Participation Agreement) has been less than 1%. We believe this is attributable primarily to a disinclination on the part of such third party owners to bear their share of the costs of the proposed well. Assuming this trend continues, we expect we will be able to use the forced pooling process to increase our relative working interest in wells in which we elect to participate, which would lead to a proportionate increase in our share of the production and reserves associated with any such well. For this reason and assuming a well in which we participate is successfully drilled and completed on a particular proved undeveloped drilling location, we believe our proved developed reserves associated with such well likely will exceed the proved undeveloped reserves previously estimated to relate to our interest in such proved undeveloped drilling location.

Principal Customers

Our principal products are crude oil, natural gas liquids and natural gas, which are marketed and sold primarily to purchasers that have access to nearby pipeline facilities, refineries or other markets. Typically, crude oil is sold at the wellhead at field-posted prices, and natural gas liquids and natural gas are sold both (i) under contract at negotiated prices based upon factors normally considered in the industry (such as distance from well to pipeline, pressure, and quality) and (ii) at spot prices.

We rely on our midstream partners for the transportation, marketing, sales and account reporting for all production. The New Source Group is responsible for the marketing and sales of all production to regional purchasers of petroleum products, and we evaluate the creditworthiness of those purchasers periodically. Although historically all of the natural gas, natural gas liquids and crude oil produced from our Golden Lane field properties have been sold to a limited number of purchasers, we believe that we would be able to secure replacement purchasers if any of these purchasers were unable to continue to purchase the natural gas and crude oil produced at our properties.

Natural Gas Liquids and Natural Gas Sales/Customers: New Dominion has previously dedicated all natural gas liquids and natural gas produced and sold from wells it operates in the Golden Lane field to Scissortail Energy, LLC, a subsidiary of Copano Energy (“Scissortail”), pursuant to a long-term gas sales contract entered into on May 1, 2005, between a member of the New Source Group and Scissortail. As part of the consideration for our long-term gas dedication, Scissortail constructed and owns a gas processing plant in Paden, Oklahoma, where the gas from the Golden Lane field is processed. None of these purchasers is affiliated in any way with us or any of the other entities controlled by Mr. Chernicky. Sales to Scissortail comprised 84% of our total sales for the year ended December 31, 2012.

Crude Oil Sales/Customers: The crude oil produced from our properties is sold to third-party marketing companies, presently United Petroleum Purchasing Company (“UPP”). These contracts are presently for terms of six months or less, which is customary for oil sales contracts. During the year ended December 31, 2012, 100% of total oil production from our properties in the Golden Lane field was sold to United Petroleum Purchasing Company, which is not affiliated in any way with us or any of the other entities controlled by Mr. Chernicky. Sales to UPP comprised 16% of our total sales for the year ended December 31, 2012.

Competition

Golden Lane Participation Agreement

In conjunction with the closing of our IPO, we acquired record title from New Source Energy to the leasehold interests that relate to the proved reserves detailed in our reserve report, and we became a party to the Golden Lane Participation Agreement. The other parties to the Golden Lane Participation Agreement include New Dominion, as operator, New Source Energy and Scintilla, as continuing working interest owners, and a number of unaffiliated entities that also own working interests in the Golden Lane field.

The Golden Lane Participation Agreement controls the development and operation of the Golden Lane field and provides New Dominion, as operator, with authority to control the development and operation of the field. New Dominion’s control rights are subject to its agreement to use its commercially reasonable efforts to conduct its operations in a manner consistent with the development agreement described below. New Dominion is empowered to acquire additional leasehold within the Golden Lane field for the account of the working interest owners in exchange for a turnkey fee per net acre acquired. This turnkey fee is currently $300 per net acre acquired and may be increased by New Dominion from time to time in the event of an increase in prevailing leasehold acquisition costs. The Golden Lane Participation Agreement permits New Dominion to hold record title to any undeveloped leasehold within the Golden Lane area of mutual interest that it acquires in the future for the benefit of the parties to the Golden Lane Participation Agreement until such time as development of the applicable leasehold commences. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold for a turnkey acreage fee then applicable under the Golden Lane Participation Agreement until development has commenced. Although New Dominion would hold record title to any such undeveloped leasehold, the Golden Lane Participation Agreement requires the assignment to us of the leasehold when development commences, and it is this right on which we will rely in connection with estimating any proved undeveloped reserves associated with such acreage hereafter acquired by New Dominion for our benefit in our future reserve reports. Each party to the Golden Lane Participation Agreement has committed to participate in future wells proposed by the operator for its proportionate share of the costs associated with such wells. The parties also have agreed to pay New Dominion their proportionate shares of an initial connection charge of $300,000 per well in the Golden Lane field, subject to increase in certain circumstances, for connection and access to its saltwater disposal infrastructure within the Golden Lane field and also to pay New Dominion their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

In the event that New Dominion acquires additional leasehold acreage for the benefit of the parties to the Golden Lane Participation Agreement (including by means of forced pooling) and subsequently commences development, New Dominion will assign record title to the other parties to the Golden Lane Participation Agreement in their proportionate share. In connection with any such assignment, New Dominion will retain an overriding royalty interest in an amount equal to 20.0% less any existing royalties or overriding royalty interests that burden the applicable lease; however, if existing royalties and overriding royalty interests exceed 20.0% in the aggregate for a particular lease, New Dominion will not retain an overriding royalty interest with respect to such lease. Additionally, if New Dominion is unable to acquire the entirety of the oil and gas leasehold estate under the drilling and spacing unit for a proposed well, then each party’s share of the ownership within such drilling and spacing unit shall be proportionately reduced in any assignment pursuant to the Golden Lane Participation Agreement. Further, if New Dominion is unable to acquire all depths and formations attributable to a particular lease, then the proportionate share of each of the parties with respect to such lease included within any assignment pursuant to the Golden Lane Participation Agreement shall be limited to only those depths and formations so acquired by New Dominion.

The Golden Lane Participation Agreement requires us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. The Golden Lane Participation Agreement contains significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements, as is customary in the oil and natural gas industry. If a party declines to participate in a new well that New Dominion proposes, such party will not be eligible to participate in the next four wells in adjacent drilling and spacing units to such proposed well (unless the proposed well is in an undrilled township and range, in which case such party will not be eligible to participate in the next eight wells in adjacent drilling and spacing units to the proposed well), and such party also would be obligated to pay for its share of the applicable acquisition costs associated with the leasehold interests underlying the proposed new well even though it has elected not to participate in the well and the associated costs themselves. In addition, if a party declines to participate in a new well that New Dominion proposes, such party will relinquish its interest in the new well and its share of production from the new well until such time at which the proceeds from such relinquished interest paid to the working interest owners that elected to participate in the new well reach specified aggregate thresholds intended to compensate the parties for the election not to participate. The Golden Lane Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs within 30 days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs later.

In return for serving as the operator of the Golden Lane field, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Golden Lane Participation Agreement, including allocable shares of its employees and certain other general and administrative expenses, under joint account procedures common in the oil and natural gas industry. We generally are required to pay our proportionate share of these ongoing costs associated with the operation of our wells on a monthly basis and within 30 days of the date of New Dominion’s invoice.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes, environmental requirements, worker health and safety standards and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties, corrective action or remedial obligations and injunctions limiting or prohibiting some or all of the New Source Group’s operations on our behalf. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the oil and natural gas industry are regularly considered by Congress, state governments, the Federal Energy Regulatory Commission (“FERC”), the EPA, the CFTC and the courts. We believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. We are not currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.

Regulation of transportation of oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act (the “ICA”), the Energy Policy Act of 1992 (“EPAct”) and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA, which are commonly referred to as “grandfathered rates.” Pursuant to EPAct 1992, FERC also adopted a generally applicable ratemaking methodology, which, as currently in effect, allows petroleum pipelines to change their rates provided they do not exceed prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods (“PPI”), plus 1.3%. For the five-year period that began July 1, 2011, the index is PPI plus 2.65%.

FERC has also established cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline may file rates based on its cost-of-service if there is a substantial divergence between its actual costs of providing service and the rate resulting from application of the index. A pipeline may charge market-based rates if it establishes that it lacks significant market power in the affected markets. Further, a pipeline may establish rates through settlement with all current non-affiliated shippers. Shippers also may challenge rates before FERC.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory, common carrier basis. Under this standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

Regulation of transportation and sales of natural gas

FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affect the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. FERC has now permanently lifted the ceiling on short-term releases and adopted regulations that facilitate the use of asset managers to manage pipeline capacity.

Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. To the extent that FERC issues an order which reclassifies transmission facilities as gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Oklahoma, where all of our properties are presently located, and other states have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, most states, including Oklahoma, impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within their jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Market transparency rules

In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Pursuant to Order No. 704, wholesale buyers and sellers of annual quantities of 2.2 million MMBtu or more of natural gas in the previous calendar year, including intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, by May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. Some of our operations may be required to comply with Order No. 704’s annual reporting requirements.

In 2008, the FERC issued Order No. 720, which increases the Internet posting obligations of interstate pipelines, and also requires “major non-interstate” pipelines (defined as pipelines that are not natural gas companies under the Natural Gas Act that deliver more than 50 million MMBtu annually and including gathering systems) to post on the Internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater. Numerous parties requested modification or reconsideration of this rule. An order on rehearing, Order No. 720-A, was issued on January 21, 2010. In that order FERC reaffirmed its holding that it has jurisdiction over major non-interstate pipelines for the purpose of requiring public disclosure of information to enhance market transparency. Order No. 720-A also granted clarification regarding application of the rule. In October 2011, the Fifth U.S. Circuit Court of Appeals vacated the order with respect to major non-interstate pipelines.

In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the Natural Gas Policy Act of 1978 and “Hinshaw” pipelines operating under Section 1(c) of the Natural Gas Act to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such information must be supplied through a new electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. In December 2010, the Commission issued Order No. 735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring Section 311 and “Hinshaw” pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans. In January 2012, FERC revised the reporting requirements applicable to storage.

There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. In December 2011, both Houses passed bipartisan legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules. In addition, the Pipeline and Hazardous Materials Safety Administration announced an intention to strengthen its rules and recently promulgated new regulations extending safety rules to certain low pressure, small diameter pipelines in rural areas.

Air emissions

The federal Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations, through the establishment of air emissions standards and associated construction and operating permitting programs and also imposes various monitoring, testing and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. Covered emissions sources of the New Source Group subject to new or emerging laws or regulations restricting such air pollutants may be required to incur certain capital expenditures over the next several years, which expenditures may be significant.

Climate change

Based on findings made by the U.S. Environmental Protection Agency (“EPA”) in December 2009 that emissions of carbon dioxide, or CO2, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, the EPA adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect the New Source Group operations and restrict or delay or ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of the New Source Group operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact New Source Group operations, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the New Source Group’s equipment and operations could result in increased costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with those operations, and such requirements also could adversely affect demand for the oil and natural gas that are produced by the New Source Group from our properties.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas or otherwise cause the New Source Group to incur significant costs in preparing for or responding to those effects and have an indirect effect on our financing and the results of our operations.

Spills and discharges

The operations conducted by the New Source Group on our behalf are subject to Oklahoma Corporation Commission requirements, including regulations for responding to and remediating spills. Furthermore, the facilities maintain Spill, Prevention, Control and Countermeasure (“SPCC”) Plans that set out measures for oil spill prevention, preparedness, and responses in accordance with the Federal Water Pollution Control Act, as amended, which also is known as the Clean Water Act (“CWA”).

The CWA and analogous state laws impose restrictions and controls regarding the discharge of pollutants into waters of the United States and state waters. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into regulated waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Other laws

The Oil Pollution Act of 1990, as amended (“OPA”) establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S. The OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

Regulated Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation and Liability Act, as amended, or CERCLA, also known as the Superfund law, and comparable state laws impose liability, without regard to fault or legality of conduct, on classes of persons considered to be responsible for the release of a “hazardous substance” into the environment, including the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In the course of its operations, the New Source Group generates materials that may be regulated as hazardous substances. In addition, the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and their implementing regulations regulate the generation, storage, treatment, transportation, disposal and cleanup of hazardous and non-hazardous solid wastes. Currently, drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or natural gas, if properly handled, are exempt from regulation as hazardous waste under Subtitle C of RCRA and, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, any loss of this RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in the New Source Group’s costs to manage and dispose of generated wastes, which could have a material adverse effect on the New Source Group’s and our results of operations and financial position. In the course of the New Source Group’s operations, it generates some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. Because of historical and/or current operating practices upon our properties by the New Source Group and/or third party predecessor owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under the New Source Group’s or our control, those properties may have become impacted and may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the New Source Group or we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.

Worker Safety

In the performance of oil and natural gas exploration and production operations on our behalf, New Source Group is subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to- Know Act and comparable state statutes and any implementing regulations require that the New Source Group organize and/or disclose information about hazardous materials used or produced in those operations and that this information be provided to employees, state and local governmental authorities and citizens. In connection with the performance of these operations, we believe that New Source Group is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Employees

As of December 31, 2012, New Source Energy had 9 full-time employees working in support of the operation of the Partnership Properties. None of these employees is represented by a labor union or covered by any collective bargaining agreement. We believe that relations with these employees are satisfactory.

Insurance Matters

As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a materially adverse effect on our financial position, results of operations or cash flows.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.newsource.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. No information from either the SEC’s website or our website is incorporated herein by reference.

ITEM 1A.

RISK FACTORS

You should consider carefully the following risk factors together with all of the other information included in this Annual Report on Form 10-K and our other reports filed with the SEC before investing in our common units. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash to pay the minimum quarterly distribution on our common units following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.

We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $0.525 per unit or any other amount. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders.

The amount of cash we distribute on our units principally depends on the cash we generate from operations, which depends on, among other things:

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

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

the amount and timing of settlements of our commodity derivatives;

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

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

For a description of additional restrictions and factors that may affect our ability to make cash distributions to our unitholders, please read “Item 5—Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.”

We rely on New Source Energy and New Dominion, our contract operator, to execute our drilling program. If either New Source Energy or New Dominion fails to perform or inadequately performs, our operations will be adversely affected and our costs could increase or our reserves may not be developed, reducing our future levels of production and our cash flow from operations, which could affect our ability to make cash distributions to our unitholders.

We have entered into agreements with New Source Energy and New Dominion, under which we rely on New Dominion to operate all of our existing producing wells and coordinate our development drilling program. For example, pursuant to our development agreement with New Source Energy and New Dominion, our general partner has the ability to propose an annual drilling schedule as well as to determine our annual maintenance drilling budget. We are a party to the Golden Lane Participation Agreement, pursuant to which New Dominion serves as the contract operator for the Partnership Properties. While under the terms of the development agreement, New Dominion is required to use its commercially reasonable efforts to ensure that our proportionate share of capital costs under the Golden Lane Participation Agreement are equal to our general partner’s proposed annual maintenance budget, New Dominion has the ability to propose upward or downward revisions to that budget subject to the approval of our general partner. Similarly, while our general partner is required to establish an annual drilling schedule, New Dominion may propose additions, substitutions or deletions subject to the approval of our general partner. Changes to either the budget or the drilling schedule could results from non-participation elections from other parties to the Golden Lane Participation Agreement, weather related events that interrupt the drilling schedule, operating results from completed or development wells or forced pooling. To the extent any of these events results in the development of less additional production or reserves than we currently anticipate, our cash flow from operations may be materially impaired.

Under the omnibus agreement, New Source Energy also provides us with management and administrative services that we believe are necessary to allow our general partner to operate, manage and grow our business. If the New Source Group fails to perform or inadequately performs these functions, our operations would be adversely affected and our costs could increase or our reserves may not be developed or properly developed, reducing our future levels of production and our cash flow from operations, which could affect our ability to make cash distributions to you.

Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions.

A decline in oil, natural gas and NGL prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The price we receive for our oil, natural gas and NGLs heavily influences our revenue, profitability, access to capital and future rate of growth. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

worldwide and regional economic and political conditions impacting the global supply and demand for oil, natural gas and NGLs;

the price and quantity of imports of foreign oil and natural gas;

the level of global oil and natural gas exploration and production;

the level of global oil and natural gas inventories;

localized supply and demand fundamentals and transportation availability;

weather conditions and natural disasters;

domestic and foreign governmental regulations;

speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

price and availability of competitors’ supplies of oil and natural gas;

the actions of the Organization of Petroleum Exporting Countries, or OPEC;

technological advances affecting energy consumption; and

the price and availability of alternative fuels.

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 72% of our estimated proved reserves as of December 31, 2012 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2012, the daily NYMEX West Texas Intermediate oil spot price ranged from a high of $109.39 per Bbl to a low of $77.72 per Bbl, and the NYMEX natural gas Henry Hub spot price ranged from a high of $3.77 to a low of $1.82 per MMBtu.

Substantially all of our oil production is sold to purchasers under short-term (less than twelve months) contracts at market based prices. Lower oil, natural gas and NGL prices will reduce our cash flows, borrowing ability and the present value of our reserves. Lower prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves.

Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.

We will be unable to sustain our minimum quarterly distribution without substantial capital expenditures that maintain our asset base. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our current proved reserves will decline as reserves are produced and, therefore, our level of production and cash flows will be affected adversely unless we participate in successful development activities or acquire properties containing proved reserves. Thus, our future oil and natural gas production and, therefore, our cash flow from operations are highly dependent upon the level of success we, in conjunction with the New Source Group, have in finding or acquiring additional reserves. However, we cannot assure you that our future activities will result in any specific amount of additional proved reserves or that the New Source Group will be able to drill productive wells at acceptable costs. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.

According to estimates included in our proved reserve report, if on December 31, 2012 drilling and development on our properties had ceased, including recompletions and workovers, then our proved developed producing reserves would decline at an annual effective rate of 11.4% over 10 years. If we fail to replace reserves, our level of production and cash flows will be affected adversely. Our total proved reserves will decline as reserves are produced unless the New Source Group conducts other successful exploration and development activities or we acquire properties containing proved reserves, or both.

We do not currently operate any of our drilling locations, and therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of our assets.

We do not currently operate any of our properties and do not have plans to develop the capacity to operate any of our properties. As a non-operated working interest owner, we are dependent on the New Source Group to develop our properties. Other than as provided in our development agreement, our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by the New Source Group over which we have little or no control. Such decisions include:

the timing of capital expenditures;

the timing of initiating the drilling and recompleting of wells;

the extent of operating costs;

selection of technology and drilling and completion methods; and

the rate of production of reserves, if any.

The Golden Lane Participation Agreement contains terms that may be disadvantageous to us.

In connection with our entry into the development agreement with New Source Energy and New Dominion, we became a party to the Golden Lane Participation Agreement, which includes both affiliated and third party lease holders in the Golden Lane field. While our general partner has the ability to establish our annual maintenance drilling budget and drilling schedule and New Dominion has agreed to use its commercially reasonable best efforts to comply with each, New Dominion serves as the contract operator under the terms of the Participation Agreement and, as among the balance of the participants in that agreement, has the sole right to propose new wells. In addition, New Dominion has the ability to propose changes to either our annual maintenance drilling budget or the drilling schedule, with such changes being subject to the approval of our general partner. In addition, the Golden Lane Participation Agreement contains negotiated terms that may depart from those typical in operating agreements, which grant New Dominion a high degree of control over the development of the Partnership Properties. Such terms include the following:

New Dominion may retain record title to our interest in any undeveloped properties that New Dominion acquires in the future for our benefit until after the drilling of and production from such properties.

Subject to our general partner’s approval, our contract operator may substitute one or more wells intended to be drilled with a new well or add additional wells. We are obligated to pay our proportionate share of any additional costs incurred.

If we decline to participate in a new well that New Dominion proposes, we will not be eligible to participate in the next four wells in adjacent drilling and spacing units to such proposed well (unless the proposed well is in an undrilled township and range, in which case we will not be eligible to participate in the next eight wells in adjacent drilling and spacing units to the proposed well), and we also would be obligated to pay for our share of the applicable acquisition costs associated with the leasehold interests underlying the proposed new well even though we have elected not to participate in the well and the associated costs themselves. In addition, if we decline to participate in a new well that New Dominion proposes, we will relinquish our interest in the new well and our share of production from the new well until such time at which the proceeds from such relinquished interest paid to the working interest owners that elected to participate in the new well reach specified aggregate thresholds intended to compensate the parties for our election not to participate.

We are obligated to pay both a well connection fee and a fee per barrel of saltwater disposed and a proportionate share of the cost to maintain such disposal wells; however, we do not obtain any ownership rights in such disposal wells, pipelines or other infrastructure.

Our annual maintenance drilling budget includes a proportionate share of the capital costs of oil, gas, water and electrical infrastructure; however, such infrastructure remains the property of our contract operator.

Our contract operator may increase certain of the fees and costs charged to us.

Certain costs charged to us are “turnkey” costs, which may be higher or lower than the actual costs incurred.

We may be liable for certain legacy liabilities related to the Partnership Properties.

Our share of oil and gas production is committed to sale arrangements that we do not control and may not reflect market terms at any given time.

Our right to sell or commit the Partnership Properties to other ventures is limited by rights held by our contract operator.

Our contract operator does not own a working interest in any of the properties it operates on our behalf. As a result, our contract operator may have interests in developing and operating the Partnership Properties that differ from and may be contrary to our interests.

If our contract operator fails to perform its obligations under its agreements with us, becomes subject to bankruptcy proceedings or otherwise proves to be an undesirable operator, our business could be adversely affected.

The successful execution of our strategy depends on continued utilization of New Dominion’s oil and gas infrastructure and technical staff as the operator of our properties. Failure to continue this relationship through (i) the termination or expiration of the operating agreements governing such relationship, or New Source Energy’s other arrangements with New Dominion and its affiliates or (ii) the bankruptcy or dissolution of New Dominion could have a material adverse effect on our operations and our financial results. In particular, if New Dominion becomes subject to bankruptcy proceedings, New Dominion or the bankruptcy trustee may be able to cancel one or more of its agreements with us on the basis that they are “executory contracts.” If this were to occur, we would be required either to renegotiate with New Dominion or its successor to continue to serve as the operator of our properties and provide us with access to the saltwater disposal and other infrastructure serving our properties or to select another operator and obtain access to similar infrastructure from other sources, any of which would most likely result in higher costs to us for such services and infrastructure, notwithstanding the omnibus agreement.

Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.

Our principal growth strategy is to pursue selective acquisitions of producing and proved undeveloped properties in conventional resource reservoirs through the New Source Group. If we choose to participate in an acquisition identified by the New Source Group, we will perform a review of the target properties that we believe is consistent with industry practices. However, these reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.

All of our producing properties and interests are currently located in the Hunton Formation in east-central Oklahoma, making us vulnerable to risks associated with operating in one primary geographic area.

All of our oil and gas assets and interests are currently in the Hunton Formation in east-central Oklahoma. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from wells in which we have an interest that are caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as in Oklahoma, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

We are subject to significant risks associated with the drilling and completion of wells in which we participate.

There are risks associated with the drilling of oil and natural gas wells, including landing the wellbore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore, fires and spills, among others. Risks in completing our wells include, but are not limited to, being able to produce the formation, being able to run tools the entire length of the wellbore during completion operations and successfully cleaning out the wellbore. The occurrence of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, blow-outs or other hazards. The payment of such liabilities could reduce the funds available to us or could, in an extreme case, result in a total loss of our properties and assets.

Our reliance on specialized processes creates uncertainties that could adversely affect our results of operations and financial condition.

One of our business strategies is to commercially develop conventional resource reservoirs using specialized processes employed by the New Source Group. One technique utilized by the New Source Group is the installation of electric submersible pumps to depressurize the targeted hydrocarbon-bearing reservoir, allowing the gas to expand and push oil and natural gas out of the pores in which they are trapped, in order to increase the production of oil and natural gas. The additional production and reserves attributable to the use of these techniques is inherently difficult to predict. If these specialized processes do not allow for the extraction of additional oil and natural gas production in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected.

We depend on our key management personnel, and the loss of any of these individuals could adversely affect our business.

If we lose the services of our key management personnel (including Mr. Kos and Mr. Chernicky) or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We depend upon the knowledge, skill and experience of these individuals to assist us in improving the performance and reducing the risks associated with our participation in oil and natural gas development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management.

Our key management personnel (including Mr. Kos and Mr. Chernicky) may terminate their employment with us at any time for any reason with little or no notice. Upon termination of their employment, such persons may engage in businesses that compete with us.

We rely on our relationships with affiliates to access infrastructure that is critical to the development of our assets. Adequate infrastructure may not be available at an economic rate.

Execution of our business strategy is dependent on the availability and capability of various infrastructure, including gas gathering and processing, saltwater disposal, and transportation. Future acquisitions may require us to expend significant capital to acquire, develop or access similar infrastructure. Such capital requirements may adversely impact our returns.

Access to saltwater disposal infrastructure may not be sufficient to handle all saltwater produced, and more stringent environmental regulations may impact the New Source Group’s ability to handle saltwater.

The proposed production is dependent on economically disposing of large amounts of saltwater utilizing the New Source Group’s existing saltwater disposal infrastructure. Changing, more stringent, environmental regulations or the unexpected production of excessive saltwater could render such infrastructure insufficient and require additional capital expenditures.

Our ability to sell our production and/or receive market prices for our production may be adversely affected by lack of transportation, capacity constraints and interruptions.

The marketability of our production from our producing properties depends in part upon the availability, proximity and capacity of third-party refineries, natural gas gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas through transportation systems that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.

A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, field labor issues or strikes, or the New Source Group might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow from operations.

Our identified drilling locations are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have identified and scheduled drilling locations on our acreage over a multi-year period. The ability of New Dominion to drill and develop these locations depends on a number of factors, including our availability of capital to fund an annual maintenance drilling budget, seasonal conditions, regulatory approvals, oil, natural gas and NGL prices, costs and drilling results. The final determination on whether to drill any of these drilling locations will be dependent upon the factors described elsewhere in this Annual Report on Form 10-K as well as, to some degree, the results of New Dominion’s drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the identified drilling locations will be drilled within our expected time frame or will ever be drilled. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations or financial condition.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K.

To prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. In addition, we may adjust estimates of proved reserves to reflect production history, results of development, prevailing oil, natural gas and NGL prices and other factors, many of which are beyond our control.

A substantial portion of our estimated proved reserves is undeveloped and may not ultimately be developed or become commercially productive, which could have a material adverse effect on our future oil and natural gas reserves and production and, therefore, our future cash flow and income.

Approximately 41% of our total estimated proved reserves as of December 31, 2012 were proved undeveloped reserves and may not be ultimately developed or produced. In estimating our proved undeveloped reserves, we rely upon estimates of our working interest and net revenue interest based on our current ownership of leasehold in the proposed drilling unit, and we also use assumed production volumes based on production histories and geological information. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in our reserve report assumes that substantial capital expenditures are required and will be made to develop these reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the standardized measure of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.

The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 2010, 2011 and 2012, we have based the estimated discounted future net revenues from our proved reserves on the unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months without giving effect to derivative transactions. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

the actual prices we receive for oil and natural gas;

our actual development and production expenditures;

the amount and timing of actual production; and

changes in governmental regulations or taxation.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K.

Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our oil and natural gas reserves.

The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGL reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and our revolving credit facility.

If we realize lower than expected cash from production, either due to lower than anticipated production levels or a decline in commodity prices from recent levels, we would need to curtail our development activities, acquisition activities, or both, or seek alternative sources of capital, including by means of entering into joint ventures with other exploration and production companies, sales of interests in certain of the Partnership Properties or by undertaking additional financing activities (including through the issuance of equity or the incurrence of debt). If we are forced to make non-consent elections to proposed wells on the Partnership Properties due to lack of capital, we would be subject to substantial penalties under the Golden Lane Participation Agreement related to relinquishment of our interest in proposed new wells and our eligibility to participate in certain additional wells.

We may not be able to access the capital markets or otherwise secure such additional financing on reasonable terms or at all, and financing may not continue to be available to us under our existing or new financing arrangements. Our business strategy is reliant upon our ability to have access to a substantial amount of outside capital. The availability of these sources of capital will depend upon a number of factors, including general economic and financial market conditions, oil, natural gas and NGL prices and our market value and operating performance. If additional capital resources are unavailable, we may curtail our development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operations.

Our cash flows from operations and access to capital are subject to a number of variables, including, among others:

our proved reserves;

the volume of oil, natural gas and NGLs we are able to produce and sell from existing wells;

the prices at which our oil, natural gas and NGLs are sold;

our ability to acquire, locate and produce new reserves; and

the ability of our banks to lend.

If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil, natural gas or NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

If oil, natural gas and NGL prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our revolving credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future that could have a material adverse effect on our ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken.

Our insurance policies might be inadequate to cover our liabilities.

Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than we do.

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small oil and natural gas company, many of our competitors are major and large independent oil and natural gas companies that possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit and may be willing to pay premium prices that we cannot afford to match. Our ability to acquire additional prospects and develop reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel or raising additional capital.

Our commodity derivative arrangements may be ineffective in managing our commodity price risk and could result in financial losses or could reduce our income, which may adversely impact our ability to pay distributions to our unitholders.

We enter into financial hedge arrangements (i.e., commodity derivative agreements) from time to time in order to manage our commodity price risk and to provide a more predictable cash flow from operations. We do not intend to designate our derivative instruments as cash flow hedges for accounting purposes. The fair value of our derivative instruments are marked to market at the end of each quarter, and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments are recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Actual future production of our properties may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, to the extent we engage in hedging activities, such hedging activities may not be as effective as we intend in reducing the volatility of our cash flows.

Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

production is less than the volume covered by the derivative instruments;

the counter-party to the derivative instrument defaults on its contract obligations;

there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies.

In addition, depending on the type of derivative arrangements we enter into, the agreements could limit the benefit we would receive from increases in oil, natural gas or natural gas liquids prices. We cannot assure you that the commodity derivative contracts we have entered into, or will enter into, will adequately protect us from fluctuations in oil prices.

The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price, interest rate and other risks associated with our business.

On July 21, 2010 new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodities Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In its rulemaking under the Act the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The position limits rule was vacated by the United States District Court (the “District Court”) for the District of Columbia in September of 2012, although the CFTC has stated that it will appeal the District Court’s decision. The CFTC also has finalized other regulations, including critical rulemakings on the definition of “swap”, “security-based swap”, “swap dealer” and “major swap participant”. The Act and CFTC rules also will require us in connection with certain derivatives activities to comply with clearing and trade-execution requirements (or take steps to qualify for an exemption to such requirements). In addition, new regulations may require us to comply with margin requirements, although these regulations are not finalized and their application to us is uncertain at this time. Other regulations also remain to be finalized, and the CFTC recently has delayed the compliance dates for various regulations already finalized. As a result, it is not possible at this time to predict with certainty the full effects of the Act and CFTC rules on us and the timing of such effects. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Act and regulations could significantly increase the cost of derivative contracts (including from swap recordkeeping and reporting requirements and through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures and our ability to pay distributions to our unitholders. Finally, the Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Our production of oil and natural gas is sold to a limited number of customers and the credit default of one of these customers could have a temporary adverse effect on us.

Our revenues are generated under contracts with a limited number of customers. Historically, all of the natural gas from our properties has been sold to Scissortail Energy, LLC and all of the oil from our properties has been sold to United Petroleum Purchasing Company and Sun Refining. Our results of operations would be adversely affected as a result of non-performance by any of our customers. A non-payment default by one of these large customers could have an adverse effect on us, temporarily reducing our cash flow.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue additional equity or incur debt, and the cost to us of any such issuance or incurrence.

Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.

Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells the New Source Group drills and the disposal of saltwater produced from such wells, among other matters. In particular, our business relies heavily on a methodology available in Oklahoma known as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling spacing unit to apply to the Oklahoma Corporation Commission for an order forcing all other holders of oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. Changes in the legal and regulatory environment governing our industry, particularly any changes to Oklahoma forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and results of our operations.

Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.

Both the Obama Administration’s budget proposal for fiscal year 2013 and other recently proposed legislation would, if enacted, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs (“IDCs”), (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our common unitholders and negatively impact the value of an investment in our common units.

The New Source Group’s operations are subject to worker health and safety as well as environmental laws and regulations which may expose the New Source Group and us to significant costs and liabilities.

The New Source Group’s oil and natural gas exploration, production and processing operations on our behalf are subject to stringent and complex federal, state, and local laws and regulations governing worker health and safety aspects of the operation, the discharge of materials into the environment and the protection of the environment. These laws and regulations may impose on those operations numerous requirements, including the obligation to obtain a permit before conducting drilling, underground injection or other activities; restrictions on the types, quantities and concentration of materials that can be released into the environment; limitations or prohibitions of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; specific health and safety criteria to protect workers; and the responsibility for cleaning up any pollution resulting from operations. Numerous governmental authorities such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. These laws and regulations may result in the assessment of administrative, civil or criminal penalties for any violations; the imposition of investigatory or remedial obligations; the issuance of injunctions limiting or preventing some or all of the operations; and delays in granting permits and cancellation of leases.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of the New Source Group’s operations, some of which may be material, due to the New Source Group’s handling of petroleum hydrocarbons and wastes, emissions to air and water, the underground injection or other disposal of wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the New Source Group and we may be liable regardless of whether either of us were at fault for the full cost of removing or remediating contamination, even when multiple parties contributed to the release and the contaminants were released in compliance with all applicable laws. In addition, accidental spills or releases on our properties may expose the New Source Group and us to significant costs or liabilities that could have a material adverse effect on our financial condition or the results of operations and our ability to make distributions to our unitholders. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for processing, reclamation or disposal and other private parties may be able to sue the New Source Group and us to enforce compliance with environmental laws and regulations, collect penalties for violations or obtain damages for any related personal injury or property damage. Some of our properties are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, emission, waste management or cleanup requirements could require the New Source Group and us to incur significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our competitive position or financial condition, the results of operations, or our ability to make distributions to our unitholders. We may not be able to recover some or any of these costs from insurance.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that the New Source Group produces for us, while the physical effects of climate change could disrupt the production and result in significant costs in preparing for or responding to those effects.

Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in producing oil and natural gas and the demand for and consumption of oil and natural gas (due to change in both costs and weather patterns). In December 2009, the EPA determined that atmospheric concentrations of GHGs present an endangerment to public health and welfare because such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Consistent with its findings, the EPA adopted regulations under the CAA that establish PSD and Title V permit reviews for GHG emissions from certain large stationary sources. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of our operations. Facilities required to obtain PSD permits for their GHG emissions will be required to meet emissions limits that are based on the “best available control technology,” which will be established by the permitting agencies on a case-by-case basis. The EPA has also adopted regulations requiring the reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, including certain oil and natural gas production facilities, which may include certain of the New Source Group’s operations on our behalf. The EPA’s GHG rules could adversely affect the New Source Group’s operations and restrict or delay the New Source Group’s ability to obtain air permits for new or modified facilities.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact the New Source Group’s operations and our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the New Source Group’s equipment and operations could require it and us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with those operations, and such requirements also could adversely affect demand for the oil and natural gas that the New Source Group produces on our behalf.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms and floods. If any such effects were to occur, they could have an adverse effect on the New Source Group’s exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and the results of operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. Our insurance may not cover some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

Risks Related to Our Indebtedness

Our revolving credit facility contains substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.

The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Our ability to comply with these restrictions and covenants in our revolving credit facility in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our revolving credit facility that are not cured or waived within the appropriate time periods provided in our revolving credit facility, all or a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.

Our revolving credit facility is reserve-based, and thus we are permitted to borrow under our revolving credit facility in 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 takes 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.

The variable rate indebtedness in our revolving credit facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Our borrowings under our revolving credit facility bear interest at rates that may vary, exposing us to interest rate risk. If such rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.

Our level of indebtedness could affect our operations in several ways, including the following:

a significant portion of our cash flows could be used to service our indebtedness;

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

the covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

a high level of debt could place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

a high level of debt may make it more likely that a reduction in the borrowing base of our revolving credit facility following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings; and

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general partnership or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil, natural gas and natural gas liquids prices, and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Our indebtedness under our revolving credit facility is secured by substantially all of our assets. Therefore, if we default on any of our obligations under the credit facility it could result in our lenders foreclosing on our assets or otherwise being entitled to revenues generated by and through our assets.

Risks Related to Our Common Units

Our general partner and its affiliates owns a controlling interest in us and will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.

Our general partner has control over all decisions related to our operations. As of March 29, 2013, New Source Energy controlled an aggregate 16.6% of our outstanding common units and all of our subordinated units, and 100% of the membership interests in our general partner is owned by New Source Energy and certain of its affiliates. Mr. Chernicky, in turn, owns 89% of the voting common stock of New Source Energy, and he also owns 1,110,250 of our common units. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner, including Mr. Chernicky and Mr. Kos, are directors and/or officers of affiliates of our general partner (including members of the New Source Group), and will continue to have economic interests, investments and other economic incentives in the New Source Group. Conflicts of interest exist and may arise in the future between our general partner and its affiliates (including members of the New Source Group), on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. These potential conflicts include, among others, the following situations:

neither our partnership agreement nor any other agreement requires New Source Energy to pursue a business strategy that favors us. The directors and officers of New Source Energy have a fiduciary duty to make decisions in the best interests of its equity holders, which may be contrary to our interests;

our general partner is allowed to take into account the interests of parties other than us, such as its owners, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

New Source Energy is not limited in its ability to compete with us, including with respect to future acquisition opportunities, and is under no obligation to offer assets to us;

except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

many of the officers and directors of our general partner who will provide services to us will devote time to affiliates of our general partner, including New Source Energy, and may be compensated for services rendered to such affiliates;

our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without such limitations, reductions, and restrictions, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

while our general partner determines the amount and timing of our drilling program under our development agreement, our contract operator, New Dominion, may propose changes to such program as a result of operating or other conditions;

our general partner determines the amount and timing of our asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to unitholders;

our general partner determines whether a cash expenditure is classified as a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus in any given period and the ability of the subordinated units to convert into common units;

we and our general partner are parties to an omnibus agreement with New Source Energy, pursuant to which, among other things, New Source Energy will perform management and administrative services for us and our general partner;

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

our partnership agreement permits us to classify up to $11.5 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

our general partner decides whether to retain separate counsel, accountants, or others to perform services for us;

our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations;

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including New Source Energy.

New Source Energy and other affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our partnership agreement provides that the New Source Group is not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, the New Source Group may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

The members of the New Source Group are established participants in the oil and natural gas industry, and each may have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders.

Neither we nor our general partner have any employees and we rely primarily on the employees of New Source Energy and New Dominion to manage our business. The management team of New Source Energy, which includes the individuals who manage us, also performs substantially similar services for its assets and operations, and thus is not solely focused on our business.

Neither we nor our general partner have any employees and we rely primarily on New Source Energy and New Dominion to operate our assets. We and our general partner have entered into various agreements with the New Source Group, pursuant to which, among other things, the New Source Group has agreed to operate our assets, perform our drilling operations and provide other management and administrative services for us and our general partner.

The New Source Group provides substantially similar services with respect to its own assets and operations. Because the New Source Group provides services to us that are substantially similar to those performed for its members, the New Source Group may not have sufficient human, technical and other resources to provide those services at a level that the New Source Group would be able to provide to us if it were solely focused on our business and operations. The New Source Group may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to the interests of our affiliates. There is no requirement that the New Source Group favor us over itself in providing its services. If the employees of the New Source Group do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.

We have previously had material weaknesses in our internal control over financial reporting. If one or more material weaknesses recur or if we fail to maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

In connection with the preparation of New Source Energy’s financial statements for the nine months ended September 30, 2011, New Source Energy identified errors in the prior calculation of its natural gas and NGL sales volumes and the related effects of those sales volumes on the calculations of depreciation, depletion and amortization expenses attributable to time periods in which its oil and natural gas properties were owned by Scintilla. New Source Energy corrected these errors, which resulted in net increases of its depreciation, depletion and amortization expenses for the years ended December 31, 2008, 2009 and 2010 of $3.8 million, $3.4 million and $4.0 million, respectively, and corresponding decreases of its net income for these periods. These changes also resulted in net decreases of New Source Energy’s oil and natural gas properties, net as of December 31, 2008, 2009 and 2010 of $6.4 million, $9.8 million and $13.8 million, respectively. Also during the preparation of New Source Energy’s financial statements for the nine months ended September 30, 2011, New Source Energy identified an error in recording goodwill related to the acquisition of other properties in the amount of the deferred income tax liability resulting from the carryover of tax attributes from the prior owners to New Source Energy.

New Source Energy management, which following the completion of our IPO constitutes our management, considered the failure to identify these errors in a timely manner to be material weaknesses in New Source Energy’s internal control over financial reporting under the standards established by the United States Public Company Accounting Oversight Board, or the “PCAOB Standards.” Under the PCAOB standards, a material weakness is defined as a deficiency, or a combination of deficiencies, in internal control, such that there is a reasonable possibility that a material misstatement of the entity’s financial statements will not be prevented, or detected and corrected on a timely basis. In response to these material weaknesses, New Source Energy evaluated its historical financial and operations data for further deficiencies and has changed the method by which it computes its natural gas and NGL sales volumes to ensure that such volumes match the actual volumes processed by its first purchasers. New Source Energy also instituted additional control procedures around the research and recording of nonrecurring transactions.

New Source Energy took all remedial actions it believed to be necessary, and we and New Source Energy are not currently aware of other material weaknesses. However, we cannot assure you that the measures taken to date, or any future measures we may implement, will prevent the recurrence of these or other similar weaknesses or ensure that we maintain adequate control over our financial processes and reporting. In addition, it is possible that we or our independent registered public accounting firm may identify additional errors in our financial statements that may be considered significant deficiencies or material weaknesses in our internal control over financial reporting.

The Sarbanes-Oxley Act of 2002 requires, among other things, that we assess the effectiveness of our internal control over financial reporting on an annual basis and the effectiveness of our disclosure controls and procedures on a quarterly basis. We are required to perform system and process evaluation and testing of our internal control over financial reporting to allow management to report on, and, after we are no longer an emerging growth company, our independent registered public accounting firm will be asked to attest to, the effectiveness of our internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002. Our testing, or subsequent testing by our independent registered public accounting firm, may reveal other material weaknesses or that the material weaknesses described above have not been fully remediated.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the Jumpstart Our Business Startups Act, or the JOBS Act. The JOBS Act contains provisions that, among other things, relax certain reporting requirements for “emerging growth companies,” including certain requirements relating to accounting standards and compensation disclosure. We are classified as an emerging growth company. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404, (2) comply with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) comply with any new audit rules adopted by the PCAOB after April 5, 2012, unless the SEC determines otherwise, (4) provide certain disclosure regarding executive compensation required of larger public companies, (5) hold nonbinding unitholder advisory votes on executive compensation or (6) obtain unitholder approval of any golden parachute payments not previously approved. In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

Cost reimbursements due to New Source Energy for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders.

We and our general partner are parties an omnibus agreement with New Source Energy pursuant to which, among other things, we make payments to New Source Energy for management and administrative services provided on our behalf. Through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of such services. After December 31, 2013, in lieu of the quarterly fee, our general partner will reimburse New Source Energy, on a quarterly basis, for all actual direct and indirect expenses it incurs in its performance under the omnibus agreement, and we will reimburse our general partner for such payments it makes to New Source Energy in an amount equal to the cost of such actual and indirect expenses, without a cap on the amount of such reimbursement. Additionally, we are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit. These payments will be substantial and will reduce the amount of cash available for distribution to unitholders.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (25%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following any reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash contribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right (if at all) to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels.

Our unitholders who fail to furnish certain information requested by our general partner or who our general partner determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.

We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner. Our general partner may require any limited partner or transferee to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units and subordinated units of any holder that is not an eligible citizen or fails to furnish the requested information.

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.

Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. The owners of our general partner have the power to appoint and remove our general partner’s directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is appointed by its owners, which are New Source Energy and certain of its affiliates. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner has control over all decisions related to our operations. New Source Energy and the chairman of its board of directors, Mr. Chernicky, collectively own approximately 33.0% of our outstanding common units, all of our subordinated units, and a 30.6% membership interest in our general partner. As a result the other unitholders do not have an ability to influence any operating decisions and are not able to prevent us from entering into any transactions. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by New Source Energy and Mr. Chernicky) after the subordination period has ended. Assuming we do not issue any additional common units and New Source Energy does not transfer its common units, New Source Energy and certain of its affiliates will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of New Source Energy and such affiliates relating to us may not be consistent with those of a majority of the other unitholders.

Our general partner is required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.

Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. Our partnership agreement does not cap the amount of maintenance capital expenditures that our general partner may estimate. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders from operating surplus will be lower than if actual maintenance capital expenditures had been deducted from operating surplus. On the other hand, if our general partner underestimates the appropriate level of estimated maintenance capital expenditures, we will have more cash available for distribution from operating surplus in the short term but will have less cash available for distribution from operating surplus in future periods when we have to increase our estimated maintenance capital expenditures to account for the previous underestimation.

Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote any units it may own, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long it acted in good faith, meaning it believed that the decisions were not adverse to the interests of our partnership;

provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners with respect to any transaction involving an affiliate if:

the transaction with an affiliate or the resolution of a conflict of interest is:

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates; or

the board of directors of our general partner acted in good faith in taking any action or failing to act;

provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Even if our unitholders are dissatisfied, they cannot remove our general partner without consent of the owners of our general partner.

The public unitholders are unable to remove our general partner without New Source Energy and certain of its affiliates consent because New Source Energy and certain of its affiliates own sufficient units to be able to prevent our general partner’s removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. New Source Energy owns approximately 39.2% of our outstanding common and subordinated units and a 5.6% membership interest in our general partner.

Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner, who are New Source Energy and certain of its affiliates, from transferring all or a portion of their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.

In addition, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.

We may not make cash distributions during periods when we record net income.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow, including cash from reserves established by our general partner, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions to our unitholders during periods when we record net losses and may not make cash distributions to our unitholders during periods when we record net income.

We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.

Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

our unitholders’ proportionate ownership interest in us will decrease;

the amount of cash available for distribution on each unit may decrease;

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

the ratio of taxable income to distributions may increase;

the relative voting strength of each previously outstanding unit may be diminished; and

the market price of our common units may decline.

Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding (other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner) cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than the then-current market price of the common units. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. New Source Energy and Mr. Chernicky collectively own approximately 33.0% of our outstanding common units and all of our subordinated units.

If we distribute cash from capital surplus, which is analogous to a return of capital, our minimum quarterly distribution will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sale of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated maintenance capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in our partnership agreement and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98.0% to our unitholders and 2.0% to our general partner, and will result in a decrease in our minimum quarterly distribution.

Our partnership agreement allows us to add to operating surplus $11.5 million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, we currently conduct business in Oklahoma and may in the future conduct business in other states. A unitholder could be liable for our obligations as if it was a general partner if:

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Our unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make distributions to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

If our common unit price declines, our unitholders could lose a significant part of their investment.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

changes in commodity prices;

changes in securities analysts’ recommendations and their estimates of our financial performance;

public reaction to our press releases, announcements and filings with the SEC;

fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies;

changes in market valuations of similar companies;

departures of key personnel;

commencement of or involvement in litigation;

variations in our quarterly results of operations or those of other oil and natural gas companies;

variations in the amount of our quarterly cash distributions to our unitholders;

future issuances and sales of our common units; and

changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry.

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our revolving credit facility may restrict our ability to make distributions.

Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our revolving credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.

The terms of our revolving credit facility restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.

Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;

conditions in the oil and natural gas industry;

the market price of, and demand for, our common units;

our results of operations and financial condition; and

prices for oil, NGLs and natural gas.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the NYSE under the symbol “NSLP.” Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of NYSE corporate governance requirements. Please read “Item 10 — Directors, Executive Officers and Corporate Governance—Management of New Source Energy Partners L.P.”

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such tax on us by any such state will reduce the cash available for distribution to our unitholders.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, you will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability resulting from that income.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have constructively terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 to its unitholders for the tax year in which the termination occurs.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Due to a number of factors including our inability to match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan of their units should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, you will likely be subject to return filing requirements and other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. We will initially own assets and conduct business in the state of Oklahoma. Oklahoma currently imposes a personal income tax and also imposes income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in Oklahoma. Further, you may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.

ITEM 2.

PROPERTIES

Our Properties

Our properties are located in the Golden Lane field within the Hunton Formation of east-central Oklahoma and consist of mature, legacy oil and natural gas reservoirs. Our properties consist of non-operated working interests in producing and undeveloped leasehold acreage, including 216 gross (82 net) producing wells with working interests ranging from 19% to 87% (38.0% weighted average); and 121gross (27.8 net) proved undeveloped drilling locations with working interests ranging from 1% to 84% (23% weighted average). As of December 31, 2012, we had 90,692 gross (32,061 net) acres in the Golden Lane field. Currently, two rigs are being used to drill on properties owned by New Source Energy, including the Partnership Properties, and the number of rigs may be increased to up to six rigs over the next twelve months, some of which may be used to drill on the Partnership Properties.

The following table summarizes information related to our estimated oil and natural gas reserves as of December 31, 2012 and the average net production for the year ended December 31, 2012 from our properties.

	Estimated Proved Reserves as of December 31, 2012(1)														Production for the Year Ended December 31, 2012				Number of Wells/ Drilling Locations as of December 31, 2012
Proved Reserves	Total Proved (MBoe)		Percent of Total		Percent Oil		Percent NGLs		Percent Natural Gas		Percentage of Depletion (2)		PV-10 (MM)(3)		Average Net Daily Production (Boe/d)		Average Working Interest		Gross		Net
Producing		8,137.9		57.1		3.0		73.5		23.5		75.0		107.6		3,147		38.0		216		82.0
Non-Producing		290.6		2.0		1.0		70.0		29.0		-		3.2		-		33.8		1		0.3
Undeveloped		5,827.1		40.9		4.8		60.4		34.8		-		30.1		-		23.0		121		27.8
Total		14,255.6		100.0		3.7		68.1		28.2		63.1		141.9		3,147		32.6		338		110.1

(1)

Proved reserves were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months, which were $94.71 per Bbl of crude oil, $34.10 per Bbl of natural gas liquids and $2.76 per Mcf of natural gas. Adjustments were made for location and the grade of the underlying resource, which resulted in an average decrease of $1.97 per Bbl of crude oil, an average decrease of $0.71 per Bbl of natural gas liquids and an average decrease of $0.17 per Mcf of natural gas.

(2)	Percentage of depletion was calculated by dividing cumulative production from our properties in these fields by the sum of proved reserves attributable to such properties and cumulative production from such properties.

(3)

PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 typically differs from the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) because it does not include the effects of income tax. We were formed in October 2012 as a partnership that is not treated as a taxable entity for federal income tax purposes and, as a result, our PV-10 and Standardized Measure will be equivalent at future dates. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity.

We use the term “conventional resource play” to refer to high water saturation (35—99%) hydrocarbon reservoirs that typically have been deemed not prospective by others. Conventional resource plays are usually located around and below conventional reservoirs, although they can exist independently. These reservoirs tend to be continuous hydrocarbon zones existing over a contiguous and potentially large geographical area. Conventional resource plays exhibit low exploration risk with consistent results, and with the implementation of specialized processes, we believe we have the ability to economically develop these large-scale reservoirs.

We have access to the development and operational experience of the New Source Group in support of our operating activities. The senior geologist and other professional staff of members of the New Source Group have developed conventional resource plays for 25 years, which have provided them with insights on the physical processes at work and a significant amount of practical operating experience in how to economically produce from these reservoirs. As a result of this experience, the New Source Group has developed and refined processes that it will utilize in developing our conventional resource plays. Prior conventional resource plays in which the senior geologist for New Source Energy has used these specialized processes to successfully and economically produce oil and natural gas include the Red Fork formation in the Mount Vernon field in central Oklahoma, which was developed in the late 1980s, and the Hunton Formation in the Carney and Golden Lane fields in central Oklahoma, which the New Source Group commenced developing in 1999. Each of these projects had been passed over by other industry operators because of its high saltwater content. The cumulative production from these fields from January 1, 1989 through December 31, 2012 following application of their specialized processes is 34.5 MMBoe.

The Hunton Formation is our only current conventional resource play in east-central Oklahoma. The Golden Lane field is located within the Hunton Formation. We intend to continue to develop our Golden Lane field where we maintain interests in approximately 216 gross (82.0 net) producing wells as of December 31, 2012 through the Golden Lane Participation Agreement. Our acreage position had 121 gross (27.8 net) proved undeveloped drilling locations as of December 31, 2012, of which 66 gross (21.6 net) are infill drilling locations. Currently, New Dominion is using two rigs to drill on our properties and may increase the number of rigs to up to six rigs over the next twelve months, some of which additional rigs may be used to drill on our properties. The New Source Group has completed an average of 25 gross wells per year, 132 of which gross wells were completed as a portion of our properties.

Oil and Natural Gas Data and Operations

Internal Controls over Reserves Estimation Process

Our management team works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Carol T. Bryant, our senior engineer, is the technical person within our company primarily responsible both for overseeing the preparation of our reserves estimates and for overseeing the reserves audit conducted by our third party petroleum engineer. Ms. Bryant has over 30 years of industry experience and has evaluated numerous properties throughout the United States with an emphasis on light oil and natural gas liquids, heavy oil, conventional and unconventional reservoirs, operations, reservoir development and property evaluation. Ms. Bryant holds a Petroleum Engineering degree from the University of Tulsa, which she received in 1980. For further information regarding Ms. Bryant’s qualifications, please see “Item 10 — Directors, Executive Officers and Corporate Governance—Management.”

Our management team plans to meet with representatives of our independent reserve engineers periodically throughout the year to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. Historically, we have had no formal committee specifically designated to review our reserves reporting and our reserves estimation process, and our reserve report was reviewed by our senior geologist and senior engineer with representatives of our independent reserve engineers and internal technical staff.

Technology Used to Establish Proved Reserves

As referred to in this Annual Report on Form 10-K, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineering firm employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, 3-D seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and 3-D seismic data were used to estimate original oil and natural gas in place in certain areas.

Independent Reserve Engineers

The proved reserves estimates as of December 31, 2012 included in this Annual Report on Form 10-K have been independently prepared by Ralph E. Davis Associates, Inc., which was founded in 1924 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1529. Within Ralph E. Davis Associates, Inc., the technical person primarily responsible for preparing the estimates shown herein was its president, Allen C. Barron. Mr. Barron has been practicing consulting petroleum engineering at Ralph E. Davis Associates, Inc. since 1993. Mr. Barron is a Registered Professional Engineer in the State of Texas (License No. 49284) and has over 40 years of practical experience in petroleum engineering, with over 30 years’ experience in the estimation and evaluation of reserves. He graduated from the University of Houston in 1968 with a Bachelors of Science in Chemical and Petroleum Engineering. Mr. Barron meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Proved Undeveloped Reserves

As of December 31, 2012, our proved undeveloped reserves were 5.8 MMBoe. All proved undeveloped locations are scheduled to be spud within the next five years and are located in the Hunton Formation in the Golden Lane field. While we are not the operator and thus not in full control of the development and operation of our properties, we believe a reasonable certainty of economic recovery exists for our proved undeveloped reserves based on the development agreement we are a party to with the New Source Group. Pursuant to the development agreement, our general partner will determine and periodically update our annual maintenance drilling budget, and will have the right to propose which wells are drilled based on our annual maintenance drilling budget.

Our eventual net leasehold position and working interests in our proved undeveloped properties will be determined through pooling and spacing procedures. For a discussion regarding additional working interests we may obtain through forced pooling, see “—Specialized Processes—Forced pooling process.”

The following table presents changes applicable to the proved undeveloped reserves on our properties during the year ended December 31, 2012 (in MBoe):

Proved undeveloped reserves as of December 31, 2011	6,408.2
Revisions(1)	(1,282.1	)
Acquisition of reserves	0.0
Extensions and discoveries	1,949.9
Conversion to proved developed reserves	(1,248.9	)
Proved undeveloped reserves as of December 31, 2012	5,827.1

(1)

The revisions in proved reserves for the year ended December 31, 2012 were due to a reduction in the peak rate of our proved undeveloped type curve based on an updated analysis of production performance, which resulted in a 20% downward adjustment to the estimated ultimate recovery of our proved undeveloped reserves.

During the year ended December 31, 2012, we developed approximately 19.4% of the proved undeveloped reserves attributable to our properties as of December 31, 2011 through the drilling of 12 gross (3.8 net) development wells at an aggregate net capital cost of approximately $8.7 million.

Production, Revenues and Price History

The following table summarizes information related to our production of our oil and natural gas products as of December 31, 2010, 2011 and 2012.

	Years Ended December 31,
	2010		2011		2012

Oil:
Production (Bbls)		68,071		48,770		61,010
Average sales price (per Bbl), excluding derivatives	$	75.45	$	92.04	$	91.30

Natural Gas:
Production (Mcf)		2,376,592		2,378,232		2,278,342
Average sales price (per Mcf), excluding derivatives	$	3.96	$	3.66	$	2.65

Natural Gas Liquids:
Production (Bbl)		658,293		720,615		711,195
Average sales price (per Bbl), excluding derivatives	$	39.36	$	45.87	$	33.74

Oil Equivalents:
Production (Boe)(1)		1,122,463		1,165,757		1,151,929
Average equivalent price (per Boe)	$	36.04	$	39.68	$	30.90
Average daily production (Boe/d)		3,075		3,194		3,147
Average production costs (per Boe)(2)	$	6.81	$	6.76	$	5.40
Average production taxes (per Boe)	$	2.56	$	1.85	$	0.99

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

(2)	Includes lease operating expense and workover expense.

For a description of our historical revenues and unit costs, see “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations.”

Drilling Activity

The following table describes the development wells drilled on our acreage by us during the years ended December 31, 2010, 2011 and 2012.

	Productive Wells				Dry Wells				Total
Year	Gross		Net		Gross		Net		Gross		Net
2010		22		7.6		—		—		22		7.6
2011		22		8.3		—		—		22		8.3
2012		12		3.8		—		—		12		3.8

We drilled no exploratory wells on our acreage during these three years.

The following table sets forth information about our wells for which drilling was in-progress or are pending completion at December 31, 2012, which are not included in the above table.

	Drilling In-Progress				Pending Completion
	Gross		Net		Gross		Net
Development wells	1		0.3		1		0.3
Exploratory wells		—		—		—		—
Total		1		0.3		1		0.3

Productive Wells

The following table sets forth the number of oil and natural gas wells in which we owned a working interest as of December 31, 2012.

Crude Oil

Natural Gas

Total

Gross

Net

Gross

Net

Gross

Net

Golden Lane

4.5

206

77.5

216

82.0

The following table sets forth the number of producing horizontal and vertical completions in which we own a working interest as of December 31, 2012.

Horizontal

Vertical

Total

Gross

Net

Gross

Net

Gross

Net

Golden Lane

188

64.2

17.8

216

82.0

Acreage

The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2012.

Undeveloped

Developed

Total

Gross

Net

Gross

Net

Gross

Net

Golden Lane

6,452

2,209

84,240

29,852

90,692

32,061

The majority of our undeveloped acreage is subject to material near-term lease expiration risk. As of December 31, 2012, we held approximately 1,529 net acres for which the leases are scheduled to expire (unless a well is drilled and oil or natural gas is produced from the leasehold) on or prior to December 31, 2015, of which 419 net acres are scheduled to expire on or prior to December 31, 2013, 496 net acres are scheduled to expire between January 1, 2014 and December 31, 2014 and 615 net acres are scheduled to expire between January 1, 2015 and December 31, 2015. Of our total estimated proved undeveloped reserves as of December 31, 2012 of 5,827.1 MBoe, 411.3 MBoe, or approximately 7.1%, is attributable to 32 gross (1.9 net) drilling locations within undeveloped acreage covered by leases set to expire before the associated wells are scheduled to be drilled. We intend, as ordinary course of business, to renew the aforementioned leases prior to expiration to avoid a reduction of our undeveloped acreage position. In addition, the impact of lease expirations may be mitigated through an acceleration of our drilling schedule. Our total proved reserves do not include any volumes which may be the result of future forced pooling efforts. While forced pooling may be available to us to help mitigate the consequences of lease expirations, we can offer no assurances in this regard. Please read “Risk Factors—Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.”

Delivery Commitments

We have no delivery commitments with respect to our production.

Title to Properties

Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business. We believe that we directly or beneficially have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, neither we nor the New Source Group conduct material investigations of title at the time we acquire undeveloped properties. We and the New Source Group make title investigations and receive title opinions of local counsel, if at all, only before commencing drilling operations. We believe that we have satisfactory title to all of our other assets.

ITEM 3.

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, 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.

New Dominion, our contract operator and an affiliate of New Source Energy, has been named as a defendant in Mattingly v. Equal Energy, which was originally filed in Creek County District Court on August 16, 2010, was subsequently removed to the United States District Court for the Northern District of Oklahoma on September 8, 2010, but was remanded to state court on August 1, 2011. The plaintiffs have asserted claims individually and on behalf of a class of royalty owners alleging that the defendants, including New Dominion, breached certain duties owed to the plaintiffs arising from oil and gas leases between the plaintiffs and the defendants by allegedly deducting post-production costs in calculating the royalties paid to the plaintiffs under those leases and failing to credit the plaintiffs for all revenues, including those attributable to the sale of natural gas, natural gas liquids, condensate and drip. The plaintiffs seek damages in excess of $10,000, punitive damages, interest, costs and attorneys’ fees.

Although we have not been made a party to this litigation, it is possible that we may be joined to the litigation as a defendant due to our acquisition of the Partnership Properties in connection with our IPO and the future calculation of royalties paid to the plaintiffs in the litigation.

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 4.

MINE SAFETY DISCLOSURES

Not Applicable.

PART II.

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are listed on the NYSE under the symbol “NSLP.”

Common units began trading on February 8, 2013, at an initial offering price of $20.00 per common unit. On March 28, 2013, the closing price for the common units was $20.30 per unit and there were approximately 2 unitholders of record of the Partnership’s common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.

We have also issued 2,205,000 subordinated units, for which there is no established public trading market. The subordinated units are held by New Source Energy Corporation.

Cash Distributions to Unitholders

We intend to make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution.

Our Cash Distribution Policy

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2013, we distribute all of our available cash to unitholders of record on the applicable record date. We will prorate the minimum quarterly distribution payable in respect of the quarter ending March 31, 2013 for the period from February 13, 2013 (the date of the closing of our initial public offering) through March 31, 2013.

Definition of Available Cash

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

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

provide for the proper conduct of our business, which could include, but is not limited to, amounts reserved for capital expenditures, working capital and operating expenses;

comply with applicable law, any of our debt instruments or other agreements; or

provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for the payment of future distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter);

plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter.

During Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner during the subordination period:

first, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

second, 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

third, 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest, that we do not issue additional classes of equity securities and that we have achieved the production necessary for holders of our subordinated units to receive a distribution on the subordinated units pursuant to the minimum annual production requirement under our partnership agreement.

After Subordination Period

Our partnership agreement requires that after the subordination period, we make distributions of available cash from operating surplus for any quarter in the following manner:

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

thereafter, in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Incentive distribution rights represent the right to receive an increasing percentage (13.0% and 23.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

first, 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $0.60375 per unit for that quarter (the “first target distribution”);

second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $0.65625 per unit for that quarter (the “second target distribution”); and

thereafter, 75.0% to all unitholders, pro rata, and 25.0% to our general partner.

Securities Authorized for Issuance under Equity Compensation Plans

See “Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2012.

Unregistered Sales of Equity Securities

None not previously reported on a current report on Form 8-K.

Issuer Purchases of Equity Securities

None.

ITEM 6.

SELECTED FINANCIAL DATA

We were formed in October 2012 and do not have historical financial operating results. The contribution of the Partnership Properties to us by New Source Energy in connection with our IPO in February 2013 was a transaction between businesses under common control. Accordingly, we will reflect the Partnership Properties in our financial statements retroactively at carryover basis, and the accounts of the Partnership Properties will become our pre-formation date accounts. Due to the factors described in “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Operating Expenses—General and administrative,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Operating Expenses—Depreciation, depletion and amortization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Income Taxes,” our future results of operations will not be comparable to the historical results attributable to the Partnership Properties and “Item 8 — Financial Statements and Supplementary Data,” both contained herein. The following table shows summary historical financial data attributable to the Partnership Properties, which comprise the entirety of our operating assets, for the periods and as of the dates presented.

The selected historical financial data attributable to the Partnership Properties as of and for the years ended December 31, 2010, 2011 and 2012 are derived from the audited historical financial statements.

The following table also presents Adjusted EBITDA, which we use in evaluating the liquidity of our business. This financial measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to net income and net cash from operating activities, its most directly comparable financial measures calculated and presented in accordance with GAAP.

	Year Ended December 31,
	2010			2011			2012
	(in thousands)
Statement of Operations Data:
Revenues:
Oil sales	$	5,136		$	4,489		$	5,570
Natural gas sales		9,409			8,713			6,030
Natural gas liquids sales		25,909			33,058			23,996
Total revenues		40,454			46,260			35,596

Operating costs and expenses:
Oil and natural gas production expenses		7,639			7,875			6,217
Oil and natural gas production taxes		2,876			2,155			1,144
General and administrative		649			6,928			12,660
Depreciation, depletion, and amortization		14,909			14,738			14,409
Accretion expense		50			55			116
Total operating costs and expenses		26,123			31,751			34,546

Operating income		14,331			14,509			1,050
Other income (expense):
Interest expense		(2,648	)		(3,735	)		(3,202	)
Realized and unrealized gains (losses) from derivatives		(516	)		(1,349	)		7,057

Income before income taxes		11,167			9,425			4,905
Income tax expense		—			10,502			1,796
Net income (loss)	$	11,167		$	(1,077	)	$	3,109

	Year Ended December 31,
	2010		2011		2012
	(in thousands)
Balance Sheet Data:
Oil and natural gas sales receivables	$	6,122	$	6,544	$	5,663
Other current assets		938		1,134		25
Total property and equipment, net		86,049		94,468		91,423
Other assets		1,430		2,674		2,823
Total assets	$	94,539	$	104,820		99,934

Current liabilities	$	4,909	$	4,076	$	1,973
Long-term debt		60,000		68,500		68,000
Other long-term liabilities		2,056		13,824		13,986
Total parent net investment		27,574		18,420		15,975
Total liabilities and parent net investment	$	94,539	$	104,820	$	99,934

	Year Ended December 31,
	2010			2011			2012
	(in thousands)
Other Financial Data:
Adjusted EBITDA	$	30,123		$	32,273		$	29,766
Cash Flow Data:
Net cash provided by operating activities	$	27,940		$	30,133		$	27,799
Net cash used in investing activities	$	(19,226	)	$	(23,818	)	$	(12,162	)
Net cash used in financing activities	$	(8,714	)	$	(6,315	)	$	(15,637	)

Non-GAAP Financial Measure

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

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 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.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

	Year Ended December 31,
	2010			2011			2012
	(in thousands)
Adjusted EBITDA Reconciliation to Net Income (loss):
Net income (loss)	$	11,167		$	(1,077	)	$	3,109
Unrealized (gain) loss on derivatives		1,349			(150	)		(1,070	)
Non-cash compensation expense		—			4,470			8,204
Accretion expense		50			55			116
Interest expense		2,648			3,735			3,202
Depreciation, depletion and amortization		14,909			14,738			14,409
Income tax expense		—			10,502			1,796
Adjusted EBITDA	$	30,123		$	32,273		$	29,766

Adjusted EBITDA Reconciliation to Net Cash Provided By Operating Activities:
Net cash provided by operating activities	$	27,940		$	30,133		$	27,799
Cash interest expense		2,262			2,250			2,553
Current income tax liability assumed by parent		—			—			172
Changes in operating assets and liabilities		(79	)		(110	)		(758	)
Adjusted EBITDA	$	30,123		$	32,273		$	29,766

ITEM 7.

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 Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the “Item 8 — Financial Statements and Supplementary Data.” 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 Annual Report on Form 10-K. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, 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 Annual Report on Form 10-K.

Overview

How We Conduct Our Business and Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

production volumes;

realized prices on the sale of natural gas, NGLs and oil, including the effect of our derivative contracts;

lease operating expenses;

general and administrative expenses; and

Adjusted EBITDA.

Production Volumes

Production volumes directly impact our results of operations. For more information about our production volumes, please read “—Results of Operations” below.

Realized Prices on the Sale of Natural Gas, NGLs and Oil

Factors affecting the sales price of our production. We sell our production to a variety of purchasers based on regional pricing. The relative prices we receive are determined by factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Natural gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The dry natural gas residue from our properties is transported and generally sold on index prices in the region. Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered and individual supply and demand dynamics at each location. Our natural gas production has historically sold at a negative basis differential from the NYMEX-Henry Hub price primarily due to the distance of the production attributable to our operating areas from the Henry Hub, which is located in Louisiana, and other location and transportation cost factors.

NGLs . Natural gas with a high energy content is referred to as “wet gas.” Certain of our properties produce wet gas, which has a higher value at the wellhead than natural gas with a lower energy content. Wet gas can be sold at the wellhead or, as is the case with our production, transported to a gas processing plant where the NGLs are separated from the wet gas leaving an NGL product called Y-Grade and dry gas residue. After processing, both the Y-Grade and dry gas residue are transported from or sold at a gas processing plant’s “tailgate.” The Y-Grade recovered from the processing of our wet gas is transported to Conway where it is fractionated into its five primary NGL components and sold based on posted prices.

When comparing prices received from production among producers in a region, it is important to compare wellhead prices as all producers have unique natural gas streams as well as unique contracts that take their natural gas to the sales markets. Because of our high energy content natural gas, we believe that our wellhead prices compare favorably with other natural gas producers with a lower energy content.

The wellhead Btu for our natural gas has an average energy content of approximately 1,498 Btu, minimal sulfur and carbon dioxide content and generally receives a premium valuation. We have previously dedicated all natural gas liquids and natural gas produced and sold from our wells operated by New Source Group in the Golden Lane field to Scissortail Energy, LLC, a subsidiary of Copano Energy (“Scissortail”), pursuant to a long-term gas sales contract entered into on May 1, 2005, between the contract operator and Scissortail. As part of the consideration for our long-term gas dedication, Scissortail constructed and owns a gas processing plant in Paden, Oklahoma, where the gas from the Golden Lane field is processed.

Oil. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials.

The crude oil produced from our properties is sold to third-party marketing companies, presently United Petroleum Purchasing Company. These contracts are presently for terms of six months or less, which is customary for oil sales contracts.

Commodity Derivative Contracts. We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. For additional information regarding our hedging policy, please read “—Liquidity and Capital Resources—Commodity Derivative Contracts.”

Lease Operating Expenses. We strive to increase our production levels to maximize our revenue and cash available for distribution. Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed.

Unlike typical oil and natural gas reservoirs, which show declining oil and gas production rates with time, the type of reservoir we currently target increases its oil and natural gas production rate over an initial period, and then, as the reservoir is depressurized, the wells assume a more typical decline curve. Similarly, the decline of saltwater volumes produced resembles the decline of hydrocarbon production following the peak production period. This reduces operating costs over time, in turn extending the economic life of the well and maximizing the hydrocarbon recovery from the reservoir.

We monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold. We typically evaluate our oil and natural gas operating costs on a per Boe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.

Production and Ad Valorem Taxes. Our production taxes are calculated as a percentage of our oil, natural gas, and NGL revenues, excluding the effects of our commodity derivative contracts. In general, as prices and volumes increase, our production taxes increase. Likewise, in general, as prices and volumes decrease, our production taxes decrease. Additionally, production tax rates vary by state, and as revenues by state vary, our production taxes will increase or decrease. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of our commodity derivative contracts. As a result we are forecasting our ad valorem taxes as a percentage of revenues, excluding the effects of our commodity derivative contracts.

General and Administrative Expenses. We and our general partner are parties to an omnibus agreement with New Source Energy, pursuant to which, among other things, New Source Energy provides management and administrative services that we believe are necessary to allow our general partner to operate, manage and grow our business. We do not have any employees. Through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of such services. 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 we will reimburse our general partner for such payments it makes to New Source Energy. Additionally, we are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit. New Source Energy has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us.

Adjusted EBITDA

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:

our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis;

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

our ability to incur and service debt and fund capital expenditures.

Adjusted EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.

Outlook

Beginning in the second half of 2008, the United States and other industrialized countries experienced a significant economic slowdown, which led to a substantial decline in worldwide energy demand. During this same period, North American natural gas supply was increasing as a result of the rise in domestic unconventional natural gas production. The combination of lower energy demand due to economic slowdown and higher North American natural gas supply resulted in significant declines in oil, NGL and natural gas prices. While oil prices have increased since the second quarter of 2009, natural gas prices remained volatile throughout 2010 and remained low in 2011 with some rebound in mid-to late 2012. Due to the expanded production and dislocation of infrastructure the relationship of NGL to oil prices has uncoupled from levels of the recent decade. This has resulted in barrels of NGL representing a price proportionately lower than that of oil. Though this has changed from the lows of 2012, and continues to increase, it remains lower than historical levels. We expect this to remain in place until market demand and infrastructure are remedied. The outlook for a worldwide economic recovery remains uncertain for the foreseeable future, and the timing of a recovery in worldwide demand for energy is unpredictable. As a result, it is likely that commodity prices will continue to be volatile in 2013. Sustained periods of low prices for oil, NGL’s or natural gas could materially and adversely affect our financial position and our access to capital.

Significant factors that may impact future commodity prices include the political and economic developments currently impacting Libya, Syria and the Middle East in general, the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas, and overall North American oil and natural gas supply and demand fundamentals. Downside risks remain in the form of a worsening Eurozone sovereign crisis, electoral and fiscal uncertainty in the US and potential deterioration in Chinese economic data. We cannot predict the occurrence of events that will affect future commodity prices or the degree to which these prices will generally approximate market prices in the geographic region of the production.

As an oil and natural gas producer, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. Our future growth will depend on our ability to continue to add estimated reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through development projects and improving the economics of producing oil and natural gas from the Partnership Properties. We expect acquisition opportunities may come from New Source Energy as well as from unrelated third parties. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.

Results of Operations

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

The following table presents selected financial and operating information. Comparative results of operations for the periods indicated are discussed below:

	Year Ended December 31,									Percent
	2011			2012			Change			Change
	(in thousands)
Statement of Operations (in thousands, except percent change):
Oil sales	$	4,489		$	5,570		$	1,081			24	%
Natural gas sales		8,713			6,030			(2,683	)		(31	)%
Natural gas liquids sales		33,058			23,996			(9,062	)		(27	)%
Total revenues		46,260			35,596			(10,664	)		(23	)%
Lease operating expenses		5,551			4,965			(586	)		(11	)%
Workover expenses		2,324			1,252			(1,072	)		(46	)%
Production taxes		2,155			1,144			(1,011	)		(47	)%
Total production expenses		10,030			7,361			(2,669	)		(27	)%
General and administrative		6,928			12,660			5,732			83	%
Depreciation, depletion, and amortization		14,738			14,409			(329	)		(2	)%
Accretion expense		55			116			61			111	%
Total operating expenses		31,751			34,546			2,795			9	%
Operating income		14,509			1,050			(13,459	)		(93	)%

Other income (expense):
Interest expense		(3,735	)		(3,202	)		533			(14	)%
Realized and unrealized gains (losses) from derivatives		(1,349	)		7,057			8,406			(623	)%
Income before income taxes		9,425			4,905			(4,520	)		(48	)%
Income tax expense		(10,502	)		(1,796	)		8,706			(83	)%
Net income (loss)	$	(1,077	)	$	3,109		$	4,186			(389	)%

Sales Volumes:
Crude oil (Bbls)		48,770			61,010			12,240			25	%
Natural gas (Mcf)		2,378,232			2,278,342			(99,890	)		(4	)%
Natural gas liquids (Bbls)		720,615			711,195			(9,420	)		(1	)%
Total crude oil equivalent (Boe)(1)		1,165,757			1,151,929			(13,828	)		(1	)%

Average Sales Price (Excluding Derivatives):
Crude oil (per Bbl)	$	92.04		$	91.30		$	(0.75	)		(1	)%
Natural gas (per Mcf)	$	3.66		$	2.65		$	(1.02	)		(28	)%
Natural gas liquids (per Bbl)	$	45.87		$	33.74		$	(12.13	)		(26	)%
Average Sales Price (per Boe)	$	39.68		$	30.90		$	(8.78	)		(22	)%

Average Production Costs (per Boe)(2):	$	6.76		$	5.40		$	(1.36	)		(20	)%

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

(2)	Includes lease operating expense and workover expense.

Oil, Natural Gas and NGL Revenues

Revenues from oil and natural gas operations were approximately $35.6 million for the year ended December 31, 2012, a decrease of $10.7 million, or 23%, compared to the year ended December 31, 2011. Of the total revenues generated during 2012, approximately 67% were generated through NGL sales, approximately 17% were generated through natural gas sales and approximately 16% were generated through oil sales. The decrease in revenues during 2012 was largely the result of significantly lower average prices of natural gas and NGLs, which were 28% and 26% lower, respectively, than those of 2011. Average oil prices were 1% lower than 2011. Crude oil production was higher by 25% while natural gas and NGL production volumes were lower by 4% and 1%, respectively.

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

•

the average realized oil price was $91.30 per Bbl during the year ended December 31, 2012, a decrease of 1% from $92.04 per Bbl during the year ended December 31, 2011;

•

total oil production was 61,010 Bbls during the year ended December 31, 2012, an increase of 25% from 48,770 Bbls during the year ended December 31, 2011 primarily because we were developing and producing from a portion of the Hunton reservoir containing a higher concentration of oil;

•

the average realized natural gas price was $2.65 per Mcf during the year ended December 31, 2012, a decrease of 28% from $3.66 per Mcf during the year ended December 31, 2011;

•

total natural gas production was 2,278,342 Mcf for the year ended December 31, 2012, a decrease of 4% from 2,378,232 Mcf for the year ended December 31, 2011;

•

the average realized natural gas liquids price was $33.74 per Bbl during the year ended December 31, 2012, a decrease of 26% from $45.87 per Bbl during the year ended December 31, 2011; and

•

total natural gas liquids production was 711,195 Bbls for the year ended December 31, 2012, a decrease of 1% from 720,615 Bbls for the year ended December 31, 2011.

Operating Expenses

Lease operating expenses. Lease operating expenses decreased $0.6 million, or 11%, to $5.0 million in 2012 from $5.6 million in 2011 due to fewer repairs and tighter control of costs.

Workover expenses. Workover expenses decreased $1.1 million, or 46%, to $1.2 million in 2012 from $2.3 million in 2011 due to fewer required workovers needed in 2012. Production costs (including workover expenses) decreased on an equivalent basis from $6.76 per Boe to $5.40 per Boe.

Production taxes. Production taxes decreased $1.0 million, or 47%, to $1.1 million in 2012 from $2.1 million in 2011. The decrease was primarily related to increased tax incentives for production from new horizontal wells and lower realized sales prices.

General and administrative. General and administrative expense increased $5.7 million, or 83%, to $12.6 million in 2012 from $6.9 million in 2011. The increase in general and administrative expense was primarily attributable to an increase in staffing costs and accounting and legal fees in 2012 as compared to 2011, in addition to $8.2 million of stock-based compensation expense incurred in 2012 compared to $4.5 million of stock-based compensation expense in 2011. In historical periods, the general and administrative expenses reflect an allocation of New Source Energy’s general and administrative expenses based on the proportion of historical production attributable to the Partnership Properties. Through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of management and administrative services. 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 we will reimburse our general partner for such payments it makes to New Source Energy.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased $0.3 million, or 2%, to $14.4 million in 2012 from $14.7 million in 2011. In historical periods, depreciation, depletion and amortization expense reflects an allocation of New Source Energy’s depreciation, depletion and amortization based on the proportion of historical production attributable to the Partnership Properties. In future periods we will compute depreciation, depletion and amortization expense by using specific production, reserves and future development costs directly attributable to the Partnership Properties, which would have decreased expense by $1.7 million in 2012 had this method been used in the 2012 period.

Other Income/Expense

Interest expense. Interest expense decreased $0.5 million, or 14%, to $3.2 million in 2012 from $3.7 million in 2011. The decrease was primarily due to the write off of loan fees of $0.7 million related to the refinancing of New Source Energy’s credit facility in 2011.

Realized and unrealized losses from derivatives. Realized and unrealized gains from derivatives were $7.1 million in 2012 compared to losses of $1.3 million in 2011. The change in realized and unrealized derivative gains and losses is primarily the result of lower natural gas and natural gas liquids settlement and futures prices in the 2012 period compared with the 2011 period. In July 2012, we liquidated all of our oil, natural gas and natural gas liquids swap and collar derivative positions and realized net proceeds of approximately $4.9 million. Subsequently in July 2012, we entered into a new fixed price swap derivative contracts for these commodities at approximately 50% of the volumes previously hedged at then current prices.

Income Taxes

Income tax expense was $1.8 million in 2012 compared to $10.5 million for the 2011. The properties were owned by a company that became a tax paying entity on August 11, 2011 and incurred deferred income taxes based on the differences in book and tax basis of the properties at that date. After completion of the transaction between NSLP and New Source, the Partnership Properties are owned by a nontaxable entity, and we will recognize a tax benefit due to the change in tax status.

Net Income (Loss)

We recorded net income of $3.1 million in 2012 compared to a net loss of $1.1 million in 2011, primarily due to derivative gains in 2012 offset by lower revenues and by higher general and administrative costs and effects of income taxes in 2011 related to the change in tax status of the Partnership Properties.

Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

The following table presents selected financial and operating information. Comparative results of operations for the periods indicated are discussed below:

	Year Ended December 31,
	2010			2011			Change			Percent Change
	(in thousands)
Statement of Operations (in thousands, except percent change):
Oil sales	$	5,136		$	4,489		$	(647	)		(13	)%
Natural gas sales		9,409			8,713			(696	)		(7	)%
Natural gas liquids sales		25,909			33,058			7,149			28	%
Total revenues		40,454			46,260			5,806			14	%

Lease operating expenses		5,318			5,551			233			4	%
Workover expenses		2,321			2,324			3		0%(or<1%)
Production taxes		2,876			2,155			(721	)		(25	)%
Total production expenses		10,515			10,030			(485	)		(5	)%

General and administrative		649			6,928			6,279			967	%
Depreciation, depletion, and amortization		14,909			14,738			(171	)		(1	)%
Accretion expense		50			55			5			10	%
Total operating expenses		26,123			31,751			5,628			22	%

Operating income		14,331			14,509			178			1	%

Other income (expense):
Interest expense		(2,648	)		(3,735	)		(1,087	)		41	%
Realized and unrealized losses from derivatives		(516	)		(1,349	)		(833	)		161	%
Income before income taxes		11,167			9,425			(1,742	)		(16	)%
Income tax expense		—			(10,502	)		(10,502	)		N/A

Net income (loss)	$	11,167		$	(1,077	)	$	(12,244	)		(110	)%

Sales Volumes:
Crude oil (Bbls)		68,071			48,770			(19,301	)		(28	)%
Natural gas (Mcf)		2,376,592			2,378,232			1,640		0%(or<1%)
Natural gas liquids (Bbls)		658,293			720,615			62,322			9	%
Total crude oil equivalent (Boe)(1)		1,122,463			1,165,757			43,294			4	%

Average Sales Price (Excluding Derivatives):
Crude oil (per Bbl)	$	75.45		$	92.04		$	16.59			22	%
Natural gas (per Mcf)	$	3.96		$	3.66		$	(0.30	)		(8	)%
Natural gas liquids (per Bbl)	$	39.36		$	45.87		$	6.51			17	%
Average Sales Price (per Boe)	$	36.04		$	39.68		$	3.64			10	%

Average Production Costs (per Boe)(2):	$	6.81		$	6.76		$	(0.05	)		(1	)%

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

(2)	Includes lease operating expense and workover expense.

Oil, Natural Gas and NGL Revenues

Revenues from oil and natural gas operations were approximately $46.3 million for the year ended December 31, 2011, an increase of $5.8 million, or 14%, compared to the year ended December 31, 2010. Of the total revenues generated during 2011, approximately 71% were generated through NGL sales, approximately 19% were generated through natural gas sales and approximately 10% were generated through oil sales. The increase in revenues during 2011 was largely the result of significantly higher average prices of oil and NGLs, which were 22% and 17% higher, respectively, than those of 2010. Average natural gas prices were 7% lower than 2010. Crude oil production was lower by 28% while natural gas and NGL production volumes were higher by 0% (or < 1%) and 9%, respectively.

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 $92.04 per Bbl during the year ended December 31, 2011, an increase of 22% from $75.45 per Bbl during the year ended December 31, 2010;

total oil production was 48,770 Bbls during the year ended December 31, 2011, a decrease of 28% from 68,071 Bbls during the year ended December 31, 2010 primarily because we were developing and producing from a portion of the Hunton reservoir containing a higher concentration of natural gas liquids and a lower concentration of oil;

the average realized natural gas price was $3.66 per Mcf during the year ended December 31, 2011, a decrease of 7% from $3.96 per Mcf during the year ended December 31, 2010;

total natural gas production was 2,378,232 Mcf for the year ended December 31, 2011, an increase of 0% (or < 1%) from 2,376,592 Mcf for the year ended December 31, 2010;

the average realized natural gas liquids price was $45.87 per Bbl during the year ended December 31, 2011, an increase of 17% from $39.36 per Bbl during the year ended December 31, 2010; and

total natural gas liquids production was 720,615 Bbls for the year ended December 31, 2011, an increase of 9% from 658,293 Bbls for the year ended December 31, 2010 primarily because we were developing and producing from a portion of the Hunton reservoir containing a higher concentration of natural gas liquids and a lower concentration of oil.

Operating Expenses

Lease operating expenses. Lease operating expenses increased $0.2 million, or 4%, to $5.6 million in 2011 from $5.3 million in 2010, and production costs (including workover expenses) decreased on an equivalent basis from $6.81 per Boe to $6.76 per Boe.

Workover expenses. Workover expenses were $2.3 million for each of the years ended December 31, 2010 and 2011.

Production taxes. Production taxes decreased $0.7 million, or 25%, to $2.2 million in 2011 from $2.9 million in 2010. The decrease was primarily related to increased tax incentives for production from new horizontal wells.

General and administrative. General and administrative expense increased $6.3 million, or 967%, to $6.9 million in 2011 from $0.6 million in 2010. The increase in general and administrative expense was primarily attributable to an increase in staffing costs and accounting and legal fees in 2011 as compared to 2010, in addition to $4.5 million of stock-based compensation expense incurred in 2011. In historical periods, the general and administrative expenses reflect an allocation of New Source Energy’s general and administrative expenses based on the proportion of historical production attributable to the Partnership Properties. Through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of management and administrative services. 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 we will reimburse our general partner for such payments it makes to New Source Energy. Additionally, we are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense decreased $0.2 million, or 1%, to $14.7 million in 2011 from $14.9 million in 2010. In historical periods, depreciation, depletion and amortization expense reflects an allocation of New Source Energy’s depreciation, depletion and amortization based on the proportion of historical production attributable to the Partnership Properties. We now compute depreciation, depletion and amortization expense by using specific production, reserves and future development costs directly attributable to the Partnership Properties, which would have increased expense by $0.8 million in 2011 had this method been used in the 2011 period.

Other Income/Expense

Interest expense. Interest expense increased $1.1 million, or 41%, to $3.7 million in 2011 from $2.6 million in 2010. The increase was primarily due to the write off of loan fees of $0.7 million related to the refinancing of New Source Energy’s credit facility and higher amortized loan fees in 2011 than in 2010.

Realized and unrealized losses from derivatives. Realized and unrealized losses from derivatives were $1.3 million in 2011 compared to $0.5 million in 2010. The increase in realized and unrealized derivative losses is the result of higher oil and natural gas liquids settlement and futures prices in 2011 compared with 2010.

Income Taxes

Income tax expense was $10.5 million in 2011 compared to none in 2010. The properties were owned by a nontaxable entity prior to August 11, 2011. Income taxes were primarily due to the differences in book and tax basis of oil and gas properties when the Properties were acquired by a taxable entity during 2011.

Net Income (Loss)

We recorded net loss of $1.1 million in 2011 compared to net income of $11.2 million in 2010 primarily due to income taxes incurred in 2011 when the properties were acquired by a taxable entity resulting in a deferred tax liability of approximately $10.5 million due to the differences in book and tax basis of oil and gas properties.

Liquidity and Capital Resources

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

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.

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

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

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 per unit. For the year ending December 31, 2013, we estimate that our maintenance capital expenditures will be approximately $8.2 million. Both we and New Source Energy believe that, by spending approximately $8.2 million annually from 2013 through 2016 to drill our proved undeveloped locations and maintain our producing wells, we will be able to at least maintain our target production through 2016. This amount represents the annual amount we expect to pay to New Dominion pursuant to the Golden Lane Participation Agreement. We intend to pay for maintenance capital expenditures from operating cash flow.

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.

Net bank repayments were approximately $0.5 million for the year ended December 31, 2012. We had net bank borrowings of $8.5 million for the year ended December 31, 2011 and no net bank borrowings for the year ended December 31, 2010. Net bank borrowings during those periods were used primarily to finance development and drilling of oil and natural gas properties.

Cash Flows

Net cash provided by operating activities was approximately $27.9 million, $30.1 million, and $27.8 million for the years ended December 31, 2010, 2011 and 2012, respectively. Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production. Production volumes in the future will in large part be dependent upon the amount of and results of future capital expenditures. Future levels of capital expenditures may vary due to many factors, including drilling results, oil, natural gas and NGL prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

Net cash used in investing activities was approximately $19.2 million, $23.8 million, and $12.2 million for the years ended December 31, 2010, 2011 and 2012, respectively. Cash flows from investing activities are related to development of oil and gas properties. Net cash used in financing activities was approximately $8.7 million, $6.3 million, and $15.6 million for the years ended December 31, 2010, 2011 and 2012, respectively. Financing cash flows are primarily related to debt and equity financing of the property development and working capital.

Working Capital

Working capital totaled $3.6 million and $3.7 million at December 31, 2011 and December 31, 2012, respectively. The collection of receivables has historically been timely. Historically, losses associated with uncollectible receivables have not been significant. We had no cash and cash equivalents at December 31, 2011 and 2012, due to the carve-out nature of the financial statements presented.

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 per unit. For the year ending December 31, 2013, we estimate that our maintenance capital expenditures will be approximately $8.2 million. Both we and New Source Energy believe that, by spending approximately $8.2 million annually from 2013 through 2016 to drill our proved undeveloped locations and maintain our producing wells, we will be able to at least maintain our target production 2016. We intend to pay for the drilling services that New Dominion will provide pursuant to the Golden Lane Participation Agreement, which we consider to be our maintenance capital expenditures, from operating cash flow.

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. Our forecast for the year ending December 31, 2013 does not reflect any material growth capital expenditures or acquisitions.

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

Revolving Credit Facility

In connection with our IPO, we entered into a four-year $60.0 million revolving credit facility with an initial borrowing base of $30.0 million. In addition, we assumed approximately $70.0 million of New Source Energy’s indebtedness under its credit facility attributable to the Partnership Properties. We used a portion of the net proceeds from our IPO, together with $15.0 million of borrowings under our revolving credit facility to (i) repay in full such assumed debt and (ii) make a distribution to New Source Energy as partial consideration for the contribution by New Source Energy of the Partnership Properties and certain commodity derivative contracts. As additional consideration for its contribution of the Partnership Properties to us in connection with the IPO, we issued a $25.0 million note payable to New Source Energy. On February 28, 2013, we entered into a First Amendment to our revolving credit facility, which added a lender, increased our borrowing base from $30.0 million to $60.0 million, and increased the lenders’ aggregate commitment from $60.0 million to $150.0 million. As a condition precedent to effectiveness of the First Amendment, we repaid the $25.0 million subordinated note issued to New Source Energy in full with borrowings under our revolving credit facility. As of March 29, 2013, we had approximately $40.0 million of outstanding borrowings under our revolving credit facility.

Our revolving credit facility is available to provide working capital for exploration and production operations, fund the acquisition of the Partnership Properties, refinance New Source Energy’s indebtedness and for general partnership purposes. The credit facility is secured by all the assets of the Partnership Properties and is guaranteed by New Source Energy. The revolving credit facility includes a $5 million sublimit for the issuance of letters of credit. The availability of the revolving credit facility is subject to certain conditions precedent.

Borrowings under the revolving credit facility bear interest at a base rate (a rate based off of the higher of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) LIBOR plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to our borrowing base utilization). Interest will be payable quarterly, or if LIBOR applies, it may be payable at more frequent intervals. In addition, the unused portion of our revolving credit facility is subject to a commitment fee of 0.50%.

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

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.

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.

Note Payable

In connection with our IPO we issued a $25.0 million note payable to New Source Energy as partial consideration for its contribution of the Partnership Properties to us. The note payable matures on February 13, 2018 and bears interest quarterly at a rate of LIBOR plus 2.50%. On February 28, 2013, this note was paid in full with borrowings under our revolving credit facility.

New Source Energy Credit Facility

On August 12, 2011, New Source Energy entered into a $150.0 million four-year credit facility with Bank of Montreal as administrative agent and KeyBank as syndication agent. We are not a co-borrower under the facility. We have included a description of this facility because we believe it is relevant to the historical financial statements presented herein and a portion of the borrowings under that facility were repaid with proceeds of our initial offering. Although the credit facility has a $150.0 million borrowing limit, New Source Energy is only entitled to borrow an amount equal to its borrowing base, which will be redetermined on a semiannual basis and at other times as directed by New Source Energy or the administrative agent. The initial borrowing base was $72.5 million. The borrowing base will be redetermined based on the reserve report prepared by engineers acceptable to the administrative agent, which we must deliver to the administrative agent on April 1 and October 1 of each year. At December 31, 2012, the borrowing base was $70.0 million.

Contractual Obligations

A summary of our contractual obligations as of December 31, 2012 is provided in the following table (in thousands).

	Obligations Due in Period
Contractual Obligation	2013-2014		2015-2016		Thereafter		Total
Long-term debt	$	—	$	68,000	$	—	$	68,000
Interest on long-term debt(1)		4,923		1,504		—		6,427
Total contractual obligations(2)	$	4,923	$	69,504	$	—	$	74,427

(1)

Estimated interest using the actual weighted average interest rate of the New Source Energy credit facility of 3.57% as of December 31, 2012. This rate is variable and could change in the future; however, we believe this is a reasonable estimate considering recent Federal Reserve interest rate policy.

(2)

On February 13, 2013, the New Source Energy credit facility debt was assumed and repaid with proceeds from the IPO and we entered into a new credit facility and borrowed $15.0 million under our credit facility. Additionally a $25.0 million subordinated note was issued to New Source Energy, which was subsequently repaid on February 28, 2013 with additional borrowings from our credit facility. Our credit facility matures on February 13, 2017.

Amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total discounted amount of estimated asset retirement obligations at December 31, 2012 is $1.5 million.

We are party to a development agreement pursuant to which we have agreed to maintain an annual maintenance drilling budget of at least $8.2 million and New Dominion has agreed to use its commercially reasonable best efforts to conduct its operations such that the Partnership’s proportionate share of capital expenses that we would consider maintenance capital pursuant to the Golden Lane Participation Agreement is equal to the annual maintenance drilling budget set by our general partner. Additionally, through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of administrative, managerial and operating services. For more information regarding such agreements, please read “Item 1 — Business—Material Definitive Agreements.”

Commodity Derivative Contracts

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

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

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.

The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business. The policies we consider to be the most significant are discussed below.

Oil and Natural Gas Properties. The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full-cost method. We utilize the full-cost method of accounting, under which all costs associated with property acquisition, exploration and development activities are capitalized. We also have the ability to capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.

Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and natural gas properties are generally calculated on a well by well or lease or field basis. Additionally, gain or loss may generally be recognized on sales of oil and natural gas properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method, since we will generally reflect a higher level of capitalized costs, as well as a higher oil and natural gas depreciation, depletion and amortization rate, and we will not have exploration expenses that successful efforts companies frequently have.

Under the full-cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred.

Historically, full cost pool amortization was recorded on a carve-out basis based on relative production from the Partnership Properties compared to total production of New Source Energy. Future full cost pool amortization will differ since production, reserves and future development costs that will be used to compute depreciation, depletion and amortization will be specific to the Partnership Properties.

We review the carrying value of our oil and natural gas properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues, less estimated future expenditures to be incurred in developing and producing the proved reserves and less any related income tax effects. Commencing with the quarter ended on December 31, 2009, in calculating estimated future net revenues, current prices have been calculated as the unweighted arithmetic average of oil and natural gas prices on the first day of each month within each applicable twelve-month period. Costs used were those as of the end of the appropriate quarterly period. For quarters prior to the fourth quarter of 2009, current prices and costs used were those as of the end of the appropriate quarterly period.

Two primary factors impacting this test are reserve levels and oil and natural gas prices and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is written off as an expense.

Oil, Natural Gas Liquids and Natural Gas Reserve Quantities. Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. We rely upon various assumptions in our estimation of proved reserves, including in the case of proved undeveloped reserves that we will participate fully in the development of our undeveloped properties pursuant to the terms of the applicable operating agreement. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of additional assumptions based on professional judgment. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil, natural gas and NGL prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

Derivative Instruments. We use commodity price and financial risk management instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of oil and natural gas derivative contract settlements and the changes in the fair value of derivative instruments that occur prior to maturity are reflected in other income in the statement of operations. Accounting guidance for derivatives and hedging establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as oil and natural gas cash flow hedges, changes in fair value, to the extent the hedge is effective, are to be recognized in other comprehensive income until the hedged item is recognized in earnings as oil and natural gas sales. Any change in the fair value resulting from ineffectiveness is recognized immediately as gains or losses in the statement of operations. All derivative instruments are recognized as either assets or liabilities in the balance sheet at fair value. None of such instruments have been designated as cash flow hedges. Accordingly, changes in the fair value of all derivative instruments have been recorded in the statements of operations.

One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.

Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.

Revenue Recognition

Oil and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil and natural gas sales such that revenues are recognized based on the share of actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage.

Equity-Based Compensation

Equity-based compensation awards are recognized in the financial statements as the cost of services received in exchange for awards of equity instruments based on the fair value of those awards at their grant date. If an award has a fixed vesting date, the cost is recognized over the period from the grant date to the vesting date(s) of the award. If an award does not have a fixed vesting date, the cost is recognized at the time it vests.

The fair value of equity awards is determined utilizing such factors as the actual and projected financial results, the principal amount of indebtedness, valuations based on financial and reserve report multiples of comparable companies, control premium, marketability considerations, valuations performed by third parties, and other factors we believe are material to the valuation process. The values reported in the financial statements are as of a point in time and do not reflect subsequent changes in market conditions and other factors.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2011 and 2012. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy, and we expect to experience inflationary pressure on the cost of oilfield services and equipment when increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

Currently, we do not have any off-balance sheet arrangements.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Realized pricing is primarily driven by the spot market prices applicable to our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile for several years, and we expect this volatility to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control, including:

developments generally impacting significant oil-producing countries and regions, such as Iraq, Iran, Syria, and Libya, the gulf coast and offshore South and Central America, Alaska and onshore U.S.;

the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas;

the overall demand for oil and natural gas in the United States and abroad;

volatility in the U.S. and global economies;

weather conditions; and

new and changing legislation and regulatory philosophy in the U.S.

Any declines in oil, natural gas and NGL prices may have an adverse impact on our financial condition, results of operations and capital resources. If oil prices decline by $10.00 per Bbl, then our Standardized Measure as of December 31, 2012 would have been lower by approximately $2.3 million. If natural gas liquids prices decline by $5.00 per Bbl, then our Standardized Measure as of December 31, 2012 would decrease by approximately $13.9 million. If natural gas prices decline by $1.00 per Mcf, then our Standardized Measure as of December 31, 2012 would decrease by approximately $8.4 million.

In order to reduce the impact of fluctuations in oil, natural gas and NGL prices on our revenues, or to protect the economics of property acquisitions, we intend to periodically enter into derivative contracts with respect to a significant portion of our estimated oil and natural gas production through various transactions that fix the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or we pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil, natural gas and NGL prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations.

Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.

Put Options. In a typical put option arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices. Our put options are exercised in cash on a monthly basis only when the floor price exceeds the reference price, otherwise they expire unsettled.

Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Our collars are exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise, they expire unsettled.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform according to the hedging arrangement. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.

Presently, all of our hedging arrangements are with one counterparty, which is a lender under our revolving credit facility. If this counterparty fails to perform its obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.

The result of natural gas market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.

The following table summarizes current hedging positions as of December 31, 2012:

	Volumes (Bbls)		Fixed Price per Bbl
Oil swaps:
2013		41,843	$	93.05
2014		15,905	$	90.20

	Volumes (Bbls)		Avg Price per Bbl		Range per Bbl
Liquid swaps:
2013		89,333	$	40.71	$	16.54 - $81.59
2014		34,410	$	39.39	$	15.91 - $79.59

	Volumes (MMBtu)		Fixed Price per MMBtu
Natural gas swaps:
2013		436,105	$	3.60

Interest Rate Risk

As of December 31, 2012, we had debt outstanding of $68.0 million, with a weighted average interest rate of 3.57% and expenses on the unused borrowing base of 0.50%. Assuming no change in the amount outstanding, the annual impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $0.2 million.

Counterparty and Customer Credit Risk

We will monitor our risk of loss due to non-performance by counterparties of their contractual obligations. We have exposure to financial institutions in the form of derivative transactions in connection with our hedging activity. The counterparty on our derivative contracts currently in place is a lender under New Source Energy’s credit facility, with an investment grade rating and we are likely to enter into any future derivative contracts with this or other lenders under our revolving credit facility that also carry investment grade ratings. If one of these counterparties were to default on any of our derivative instruments while there is an outstanding balance under our revolving credit facility, we believe we would have the ability to offset the amount of any payment owing from this counterparty against the portion of the outstanding balance under our revolving credit facility then owed to such counterparty. We expect that any future derivative transactions we enter into will be with lenders under our revolving credit facility that carry an investment grade credit rating.

We also have exposure to credit risk through our operating partners and their management of the sale of our oil and natural gas production, which they market to energy marketing companies and refineries. We anticipate that we will monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements, production, sales, marketing, engineering and reserve reports. See “Item 1 — Business—Principal Customers” for further detail about our significant customers.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Properties Contributed to New Source Energy Partners L.P.

Audited Financial Statements:

Report of Independent Registered Public Accounting Firm	82

Balance Sheets as of December 31, 2011 and 2012	83

Statements of Operations for the Years Ended December 31, 2010, 2011 and 2012	84

Statements of Parent Net Investment for the Years Ended December 31, 2010, 2011 and 2012	85

Statements of Cash Flows for the Years Ended December 31, 2010, 2011 and 2012	86

Notes to Financial Statements	87

New Source Energy Partners L.P.

Audited Financial Statements:

Report of Independent Registered Public Accounting Firm	106

Balance Sheet as of December 31, 2012	107

Notes to Balance Sheet	108

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Partners of New Source Energy Partners L.P.

Oklahoma City, Oklahoma

We have audited the accompanying carve-out balance sheets of the Properties Contributed to New Source Energy Partners L.P. (the “Partnership Properties”) as of December 31, 2011 and 2012, and the related carve-out statements of operations, parent net investment, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the management of the Partnership Properties. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership Properties are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the internal control over financial reporting of the Partnership Properties. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1, the Partnership Properties are not a stand-alone entity. The carve-out financial statements of the Partnership Properties reflect the assets, liabilities, revenues, and expenses directly attributable to the Partnership Properties, as well as allocations deemed reasonable by management, to present the financial position, results of operations, and cash flows of the Partnership Properties and do not necessarily reflect the financial position, results of operations and cash flows had the Partnership Properties operated as a stand-alone entity during the periods presented and, accordingly, may not be indicative of the Partnership Properties’ future performance.

In our opinion, the carve-out financial statements referred to above present fairly, in all material respects, the financial position of the Partnership Properties as of December 31, 2011 and December 31, 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Houston, Texas

April 1, 2013

Properties Contributed to New Source Energy Partners L.P.

Balance Sheets

(in thousands)

	As of December 31,						Pro Forma (see Note 1) December 31,
	2011			2012			2012
ASSETS
Current assets:
Oil and natural gas sales receivable	$	6,120		$	5,621		$	—	(b)
Oil and natural gas sales receivable—related parties		424			42			—	(b)
Derivative assets		1,134			25			25
Total current assets		7,678			5,688			25

Property and equipment:
Oil and natural gas properties, at cost, using full cost method:
Proved oil and natural gas properties		190,914			202,795			202,795
Prepaid drilling and completion costs		1,516			1,000			1,000
Accumulated depreciation, depletion, and amortization		(97,962	)		(112,372	)		(112,372	)
Total property and equipment, net		94,468			91,423			91,423

Loan fees, net		2,046			1,508			1,508
Deferred offering costs		—			1,315			1,315
Derivative assets		628			—			—
Total assets	$	104,820		$	99,934		$	94,271

LIABILITIES AND PARENT NET INVESTMENT:
Current liabilities:
Accounts payable	$	284		$	—		$	—
Accounts payable—related parties		1,936			1,564			16,089	(b)
Accrued liabilities.		213			259			259
Accrued income taxes		172			103			—	(a)
Derivative obligations		1,471			47			47
Total current liabilities	$	4,076		$	1,973			16,395
Long-term related party payables		594			345			25,345	(b)
Credit facility—long-term portion		68,500			68,000			68,000
Derivative obligations		1,489			107			107
Asset retirement obligation		1,411			1,510			1,510
Deferred tax liability		10,330			12,024			—	(a)
Total liabilities		86,400			83,959			111,357

Commitments and contingencies (See Note 10)
Parent net investment
Parent net investment		18,420			15,975			(17,086	)(b)
Total liabilities and parent net investment	$	104,820		$	99,934		$	94,271

See Note 1 for footnotes describing the pro forma amounts.

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

Properties Contributed to New Source Energy Partners L.P.

Statements of Operations

(in thousands, except per unit amounts)

	Years Ended December 31,
	2010			2011			2012

REVENUES
Oil sales	$	5,136		$	4,489		$	5,570
Natural gas sales		9,409			8,713			6,030
Natural gas liquids sales		25,909			33,058			23,996
Total revenues		40,454			46,260			35,596

OPERATING COSTS AND EXPENSES
Oil and natural gas production expenses		7,639			7,875			6,217
Oil and natural gas production taxes		2,876			2,155			1,144
General and administrative		649			6,928			12,660
Depreciation, depletion, and amortization		14,909			14,738			14,409
Accretion expense		50			55			116
Total operating costs and expenses		26,123			31,751			34,546

Operating income		14,331			14,509			1,050
OTHER INCOME (EXPENSE)
Interest expense		(2,648	)		(3,735	)		(3,202	)
Realized and unrealized gains (losses) from derivatives		(516	)		(1,349	)		7,057

Income before income taxes		11,167			9,425			4,905
Income tax expense		—			10,502			1,796
Net income (loss)	$	11,167		$	(1,077	)	$	3,109

Pro forma (unaudited) (See Note 1)
Net income							$	3,109
Pro forma adjustment:
Income tax benefit								1,796	(a)
Pro forma net income							$	4,905	(c)

Pro forma earnings per common unit—basic and diluted
Pro forma net income per common unit							$	0.91	(c)

See Note 1 for footnotes describing the pro forma amounts.

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

Properties Contributed to New Source Energy Partners L.P.

Statements of Parent Net Investment

(in thousands)

	Parent net investment
BALANCE, January 1, 2010	$	23,685
Net income		11,167
Distribution to parent		(7,278	)
BALANCE, December 31, 2010		27,574
Net loss		(1,077	)
Stock-based compensation		4,470
Distribution to parent		(12,547	)
BALANCE, December 31, 2011		18,420
Net income		3,109
Stock-based compensation		8,204
Distribution to parent		(13,758	)
BALANCE, December 31, 2012	$	15,975

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

Properties Contributed to New Source Energy Partners L.P.

Statements of Cash Flows

(in thousands)

	Years Ended December 31,
	2010			2011			2012

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	11,167		$	(1,077	)	$	3,109
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		14,909			14,738			14,409
Stock-based compensation		—			4,470			8,204
Write off of loan fees due to debt refinancing		—			771			—
Amortization of loan fees		386			501			603
Accretion expense		50			55			116
Deferred income taxes		—			10,330			1,694
Unrealized (gain) loss on derivatives		1,349			(150	)		(1,070	)
Changes in operating assets and liabilities:
Oil and natural gas receivables		376			3			499
Oil and natural gas sales receivables—related parties		—			(424	)		382
Accounts payable—trade		—			284			(284	)
Accounts payable—related parties		(297	)		247			160
Accrued liabilities		—			213			46
Accrued income taxes		—			172			(69	)
Net cash provided by operating activities		27,940			30,133			27,799
CASH FLOWS FROM INVESTING ACTIVITIES
Payments for oil and natural gas properties		(19,226	)		(23,818	)		(12,162	)
Net cash used in investing activities		(19,226	)		(23,818	)		(12,162	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from borrowings on credit facility		—			68,500			3,000
Payments on long-term credit facility		—			(60,000	)		(3,500	)
Payments for deferred loan costs		(1,436	)		(2,268	)		(64	)
Payments for offering costs		—			—			(1,315	)
Distribution to parent		(7,278	)		(12,547	)		(13,758	)
Net cash used in financing activities		(8,714	)		(6,315	)		(15,637	)
Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of period		—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for interest expense	$	2,262		$	2,250		$	2,553
NON-CASH INVESTING AND FINANCING ACTIVITIES
Capitalized asset retirement obligation	$	12		$	499		$	(17	)
Change in accrued capital expenditures		910			(1,160	)		(780	)
Income taxes assumed by parent		—			—			172

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

Properties Contributed to New Source Energy Partners L.P.

Notes to Financial Statements

1. Summary of Significant Accounting Policies

Organization

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

New Source Energy Partners L.P. completed an initial public offering of common units representing limited partner interests in 2013 (see Note 11). At the closing of the initial public offering (the "Offering"), New Source contributed certain oil and gas properties (the “Partnership Properties”) from their operations and related receivables, liabilities and derivatives contracts to the Company in return for approximately 50% of New Source Energy GP, LLC (which owns 2% of the NSLP units), common and subordinated units of limited partner interest and a $25.0 million subordinated note and cash.

Basis of Presentation and Nature of Operations

The accompanying financial statements have been prepared on a “carve-out” basis from New Source’s financial statements and reflect the historical accounts directly attributable to the Partnership Properties together with allocations of expenses from New Source. The Partnership Properties are recorded at the actual historical cost of exploration and development because the expected transaction was between businesses under common control. These costs were not allocated. For the reasons discussed below, the accompanying financial statements may not be indicative of the Company’s future performance nor reflect what its financial position, results of operations, changes in equity, and cash flows would have been had the Partnership Properties been operated as an independent company during the periods presented. The financial statements have been prepared in accordance with generally accepted accounting principles (“GAAP”).

New Source has performed certain corporate functions on behalf of the Partnership Properties and the financial statements reflect an allocation of the costs New Source 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 current production of producing assets. Management believes such allocations are reasonable; however, they may not be indicative of the actual expense that would have been incurred had the Partnership Properties been operating as an independent company for all of the periods presented. The charges for these functions are included primarily in general and administrative expenses. Pursuant to an omnibus agreement with New Source, New Source will provide the Company and New Source Energy GP, LLC with management and administrative services, and the Company will pay New Source a quarterly fee of $675,000 from the closing of the Company’s initial public offering until December 31, 2013. After December 31, 2013, in lieu of the quarterly fee, New Source Energy GP, LLC will reimburse New Source, on a quarterly basis, for the actual direct and indirect expenses it incurs in its performance under the omnibus agreement, and the Company will reimburse New Source Energy GP, LLC for such payments it makes to New Source. The Company also intends to provide equity compensation to the employees of New Source who provide such services to the Company.

New Source became the owner of the Partnership Properties on August 12, 2011 and reflected the Partnership Properties in its financial statements retroactively because the acquisition of the Partnership Properties was a transaction between businesses under common control. Prior to that date, the Partnership Properties were owned by a nontaxable entity. New Source is a taxable entity. Accordingly, at the acquisition date, New Source accrued deferred income taxes attributable to differences in the book and tax bases in the Partnership Properties and subsequent to the acquisition has accounted for income taxes using the asset and liability method. The Company will not be a taxable entity. Accordingly, when New Source contributed the Partnership Properties to the Company in 2013, the Company reversed the related deferred income taxes, and subsequently the Company will not reflect income taxes in its financial statements.

Depreciation, depletion and amortization of the full cost pool was calculated based on relative Boe produced from the Partnership Properties compared to total production for New Source. Prospectively, the Company’s full cost pool amortization will be calculated based on the Partnership Properties’ specific production, reserves and future development costs. Had this approach been used to calculate the Partnership Properties’ depreciation, depletion and amortization for the year ended December 31, 2012, depreciation, depletion and amortization for the year would have been less than the amounts reflected in the Partnership Properties’ financial statements by approximately $1.7 million.

Description of the Partnership Properties to be Acquired from New Source

The Partnership Properties acquired from New Source in 2013 include interests in wells producing oil, natural gas, and natural gas liquids from the Misener-Hunton (the “Hunton”) formation in East-Central Oklahoma. The Partnership Properties acquired 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.

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 New Source common stock issued as compensation for services, the allocation of general and administrative expenses and asset retirement obligations.

Oil and Natural Gas Sales Receivables

Receivables from the sale of oil and natural gas are generally unsecured. Allowances for doubtful accounts are determined based on management’s assessment of the creditworthiness of the purchaser. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts will generally be written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. No allowance was deemed necessary for the years ended December 31, 2010, 2011 and 2012.

Oil and Natural Gas Properties

The Partnership Properties utilize 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. New Source amortizes all capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, using the units-of-production method based on total proved reserves. The portion of New Source’s amortization that has been allocated to the Partnership Properties in each period is equal to the percentage of New Source’s production attributable to the Partnership Properties. 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 may not exceed the estimated future net revenues from proved oil and natural gas properties, discounted at 10% (the ceiling limitation). In arriving at estimated 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 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 future net revenues have been prepared by an independent petroleum engineer. Future net revenues were computed based on reserves using prices calculated as the unweighted arithmetical average oil and natural gas prices on the first day of each month within the latest twelve-month period. There have been no full cost ceiling write-downs recorded in the years ended December 31, 2010, 2011 and 2012.

Environmental

Oil and natural gas properties are subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the removal or mitigation of the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.

Revenue Recognition

Oil and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil and natural gas sales such that revenues are recognized based on the Partnership Properties’ share of actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. For the years ended December 31, 2010, 2011 and 2012, there were no significant oil and natural gas imbalances.

Asset Retirement Obligations

Liabilities associated with asset retirement obligations are recorded at fair value in the period in which they are incurred or when properties are acquired with a corresponding increase in the carrying amount of the related oil and natural gas properties. Subsequently, the asset retirement cost included in the carrying amount is allocated to expense through DD&A. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.

General and Administrative Expenses

New Source’s financial statements reflect an allocated portion of the actual general and administrative expense incurred by companies affiliated with New Dominion, LLC, an Oklahoma Limited Liability Company (“New Dominion”), a company under common ownership with New Source, for periods prior to August 11, 2011, and the Partnership Properties’ financial statements reflect an allocated portion of New Source’s general and administrative expenses.

A wide range of formulas for general and administrative expense allocation was considered. Management of New Source believes the most accurate and transparent method of allocating general and administrative expenses in preparing New Source’s financial statements for periods prior to August 11, 2011 is based on the historical cost of the properties is acquired on that date in proportion to the total cost of the assets of the affiliated companies from which it acquired the properties. Management of New Source believes the most accurate and transparent method of allocating general and administrative expenses in preparing the Partnership Properties’ financial statements is based on the historical production of the Partnership Properties, divided by the total combined production of the properties of New Source. Additional factors were considered, in that costs and expenses relating specifically to New Source’s write off of offering costs (as a result of New Source’s abandoned initial public offering) and acquisition related costs for New Source were excluded from the allocation of general and administrative expenses. Using this method, general and administrative expense allocated to the Company for the years ended December 31, 2010, 2011 and 2012 was $0.6 million, $6.9 million and $12.7 million, respectively.

Stock-Based Compensation

The financial statements reflect a portion of the cost of the stock-based compensation awards granted by New Source. Stock-based compensation was allocated based on the historical production of the Partnership Properties, divided by the total combined production of the properties of New Source. Allocated stock-based compensation expense is included in general and administrative expense and amounts allocated to the Company for years ended December 31, 2010, 2011 and 2012 were -$0-, $4.5 million and $8.2 million, respectively.

Awards under New Source’s long-term incentive plan may consist of restricted stock grants, stock option awards, and other awards issuable to employees and non-employee directors. New Source recognizes in its financial statements the cost of employee services received in exchange for awards of equity instruments based on the fair value of those awards at their grant date. If an award has a fixed vesting date, the cost is recognized over the period from the grant date to the vesting date(s) of the award. If an award does not have a fixed vesting date, the cost is recognized at the time it vests.

Income Taxes

Income taxes are reflected in these financial statements during the periods in which the Partnership Properties were owned by a taxable entity. Since New Source was not a taxable entity prior to August 2011, no income taxes have been provided for the periods prior to that date. Upon New Source becoming a taxable entity, the Partnership Properties were attributed a deferred tax liability of approximately $10.5 million due to the difference in tax and book bases of oil and gas properties.

Fair Value of Financial Instruments

The fair value of a financial instrument is the amount at which the instrument could be exchanged in an orderly transaction between two willing parties. The carrying amount of the borrowings under the credit facility reported on the balance sheets approximates fair value because the debt instrument carries a variable interest rate based on market interest rates. The carrying amounts of derivative assets and liabilities reported on the balance sheets are the estimated fair values of the allocated derivative instruments associated with the Partnership Properties.

Derivatives

All derivative instruments are recognized as either assets or liabilities in the balance sheet at fair value. None of such instruments have been designated as cash flow hedges. Accordingly, changes in the fair value of all derivative instruments have been recorded in the statements of operations.

Pro Forma Data

(a) Change in Tax Status

After the transfer to the Company was completed in 2013, the Partnership Properties’ operations are no longer subject to federal and state income taxes. The pro forma amounts reflected on the accompanying balance sheet and statements of operations reflect this change in tax status by eliminating current and deferred income tax liabilities and provisions.

(b) Distribution

The Company acquired the Partnership Properties in exchange for partnership units and a $25.0 million note payable to New Source and cash. The transaction will be accounted for at carryover basis because New Source and the Company are under common control. Accordingly, the $15.8 million cash payment to be made, removal of accounts receivable and certain accounts payable and issuance of the note payable will be reflected in the financial statements as a distribution to New Source. The accompanying pro forma balance sheet reflects the reduction in accounts receivable, accounts payable and the parent net investment, increases in notes payable and the corresponding liability (included in Accounts payable-related parties) for the $40.8 million distribution payable to New Source that would have been recognized had the transaction occurred as of December 31, 2012.

Pro forma net income for the year ended December 31, 2012 is presented to reflect the elimination of income tax expense, as if the Partnership Properties had been a nontaxable entity throughout the year.

Pro forma net earnings per common unit were determined by dividing pro forma net income allocable to common units by the pro forma weighted average number of common units outstanding. The denominator for the pro forma earnings per common unit calculations is 3,038,888 common units, which is equal to the sum of (a) 777,500 common units, the number of common units issued to New Source in exchange for the Partnership Properties plus (b) 2,261,388 common units, the number of common units sold in the Company’s initial public offering to fund the $40.8 million distribution discussed above. The total number of units outstanding on a pro forma basis is 5,393,888 units, which is equal to the sum of the common units, subordinated units and general partner units to be issued to New Source (3,132,500) plus 2,261,388 units to be sold to fund the distribution. Of that total, 3,038,888 units will be issued in the form of common units. Accordingly, the numerators for the pro forma earnings per common unit calculations were equal to 56.3% of the pro forma net income amount. Basic and diluted pro forma earnings per common unit are the same, as there were no potentially dilutive units outstanding.

In addition, approximately $28 million of borrowings reflected in the Partnership Properties’ financial statements were repaid in 2013 using proceeds from the Company’s initial public offering. If the pro forma net income amount reflected on the Partnership Properties’ statements of operations and described above were further adjusted to eliminate interest expense on the $28 million of borrowings to be repaid, pro forma net income and pro forma net income allocable to common units would have been $7.0 million and $4.6 million for the year ended December 31, 2012. The denominator for the pro forma earnings per common unit calculation would have been increased by 1.6 million common units, the number of common units expected to be sold in the Company’s initial public offering to fund the $28 million repayment. Basic and diluted pro forma earnings per common unit reflecting these additional adjustments would have been $1.01 for the year ended December 31, 2012.

2. Asset Retirement Obligations

Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon, and remediate producing properties at the end of their productive lives in accordance with applicable laws. There were no assets legally restricted for purposes of settling asset retirement obligations as of December 31, 2010, 2011 and 2012.

The following table summarizes activity associated with asset retirement obligations for the periods presented:

	Year Ended December 31,
	2010		2011		2012
	(in thousands)
Asset retirement obligations, beginning of period	$	795	$	857	$	1,411
Liabilities incurred from new wells drilled and acquired		12		499		34
Revision of previous estimates		—		—		(51	)
Accretion expense		50		55		116
Asset retirement obligations, end of period	$	857	$	1,411	$	1,510

3. Major Customers

The Partnership Properties produce exclusively from the Hunton formation in east-central Oklahoma. The following table represents oil and natural gas sales of our oil and natural gas production by customer for 2010, 2011 and 2012:

Purchaser	2010			2011			2012
Scissortail		87	%		90	%		84	%
United Petroleum Purchasing		—		<10%				16	%
Sun Refining		13	%	<10%				—

This market is served by multiple oil and natural gas purchasers. As a result, the loss of any one purchaser would not have a material adverse effect on the ability of the Partnership Properties to sell their oil and natural gas production.

4. Related Party Transactions

New Dominion, LLC

New Source is affiliated by common ownership, and has a working relationship with New Dominion, LLC, an exploration and production operator based in Tulsa, Oklahoma.

New Dominion is currently contracted to operate New Source’s existing wells in the Hunton formation in east-central Oklahoma. New Dominion has historically performed this service for New Source. As a result, substantially all of the historical accounts payable related to the Partnership Properties are presented as accounts payable—related party in the accompanying balance sheets. Producing overhead charges from New Dominion included in the Partnership Properties’ oil and natural gas expenses, drilling and completion overhead charges from New Dominion included in the Partnership Properties’ full cost pool of oil and natural gas properties, and saltwater disposal fee charges from New Dominion included in the Partnership Properties’ oil and natural gas expenses are shown below for the respective periods. The overhead charges were calculated by multiplying the overhead rate for each well by the working interest associated with the Partnership Properties.

	Year Ended December 31,
	2010		2011		2012
	(in thousands)
Producing overhead charges	$	585	$	581	$	599
Drilling and completion overhead charges	$	44	$	26	$	27
Saltwater disposal fees	$	2,233	$	1,612	$	1,642

5. Credit Facility

The accompanying financial statements reflect an allocated portion of the debt, loan fees, and interest expense associated with credit facilities of New Dominion, Scintilla (an entity controlled by New Dominion’s controlling stockholder) and New Source under which the Partnership Properties were pledged as collateral. The principal amount that was allocated is equal to the total amount of such outstanding borrowings (the amount of such debt that was repaid with the proceeds from the offering described in Note 1 and borrowing under a new Company credit facility plus the $25.0 million note payable issued to New Source upon closing of the offering). The loan fees and interest expense were allocated based on the proportionate share of the allocated principal amount to the total principal amount outstanding.

In February 2010, a prior credit facility was refinanced and loan fees attributable to the refinanced facility of $1.4 million were recorded as other assets and were being amortized over the life of the new loan.

In August 2011, this prior facility was paid in full with the proceeds from a new New Source credit facility. Unamortized loan fees on the prior facility of approximately $0.8 million represented an extinguishment of debt charge which has been included in interest expense for the year ended December 31, 2011.

On August 12, 2011, New Source entered into a $150.0 million four-year credit facility with Bank of Montreal as administrative agent and KeyBank as syndication agent. The initial borrowing base was $72.5 million. The borrowing base is re-determined based on reserve reports prepared by engineers acceptable to the administrative agent, which New Source must deliver to the administrative agent on April 1 and October 1 of each year.

As a result of the derivative commodity transactions in July 2012 (see Note 7), New Source’s credit facility borrowing base was re-determined by the administrative agent and, on August 2, 2012 New Source’s borrowing base was reduced from $72.5 million to $70 million.

As of December 31, 2012, New Source had approximately $68.0 million outstanding under its credit facility and, as a result, New Source had $2.0 million of available borrowing capacity under the credit facility. New Source was in compliance with all debt covenants as of December 31, 2012.

6. 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 Financial Accounting Standards Board Accounting Standards Codification Topic (“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. Fair value measurements are classified and disclosed in one of the following categories:

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.

Fair Value on a Non-Recurring Basis

The Partnership Properties follow the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to the Partnership Properties, ASC 8201-10, applies to common stock issued for compensation purposes and the initial recognition of asset retirement obligations for which fair value is used.

New Source utilizes ASC Topic 718, “Compensation—Stock Compensation,” to value shares issued for compensation purposes. Measurement of share-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 Properties have designated these liabilities as Level 3.

The carrying amount of the revolving long-term debt of $68.0 million as of December 31, 2012 approximates fair value because New Source’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.

7. Derivative Contracts

The accompanying financial statements reflect an allocated portion of New Dominion/ Scintilla and New Source’s derivative contracts. The amount of derivative contracts that has been allocated is based on the proportionate share of the production from the Partnership Properties to total New Source production. Various hedging strategies are utilized to manage the price received for a portion of the future oil and natural gas production to reduce exposure to fluctuations in oil and natural gas prices and to achieve a more predictable cash flow.

For the years ended December 31, 2010, 2011 and 2012, realized gains (losses) on commodity derivatives associated with the Partnership Properties amounted to $0.8 million, $(1.5) million and $6.0 million, while unrealized gains (losses) amounted to $(1.3) million, $0.2 million and $1.1 million, respectively.

On July 12, 2012, New Source liquidated all of its oil, natural gas and natural gas liquids swap and collar derivative positions and received proceeds of approximately $4.9 million. On July 19, 2012, New Source entered into new, fixed price derivative swap contracts for oil, natural gas and natural gas liquids for approximately 50% of the volumes that were previously hedged at current prices.

Allocated commodity derivative positions at December 31, 2011 were as follows:

	Volumes (Bbls)		Floor Price		Ceiling Price

Oil collars:
2012		122,607	$	72.00	$	112.02
2013		83,297	$	72.00	$	118.76
2014		31,662	$	86.01	$	116.97

	Volumes (Bbls)		Avg Price per Bbl		Range per Bbl
Liquid swaps:
2012		221,251	$	53.17	$16.76	-	$100.00
2013		177,847	$	44.60	$15.79	-	$96.60
2014		68,506	$	47.59	$17.22	-	$96.60

	Volumes (MMBtu)		Floor Price		Ceiling Price
Natural gas collars:
2012		1,256,631	$	4.00	$	4.72
2013		868,208	$	4.25	$	5.43

Allocated commodity derivative positions at December 31, 2012 are as follows:

	Volumes (Bbls)		Fixed Price per Bbl

Oil swaps:
2013		41,843	$	93.05
2014		15,905	$	90.20

	Volumes (Bbls)		Avg Price per Bbl		Range per Bbl
Liquid swaps:
2013		89,333	$	40,71	$16.54	-	$81.59
2014		34,410	$	39.39	$15.91	-	$79.59

	Volumes (MMBtu)		Fixed Price per MMBtu
Natural gas swaps:
2013		436,105	$	3.60

The following table sets forth by level within the fair value hierarchy, the allocated derivative assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2011:

	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)		Unobservable Inputs (Level 3)			Total Carrying Value
	(in thousands)
NGL swaps	$	—	$	—	$	(2,068	)	$	(2,068	)
Oil and natural gas collars		—		—		870			870
Total as of December 31, 2011	$	—	$	—	$	(1,198	)	$	(1,198	)

	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
	(in thousands)
NGL swaps	$	—	$	—		$	(112	)	$	(112	)
Oil and natural gas swaps		—		(17	)		—			(17	)
Total as of December 31, 2012	$	—	$	(17	)	$	(112	)	$	(129	)

Estimates of the fair values of the commodity derivatives are based on published and estimated forward commodity price curves provided by third party counterparties for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available.

The following table sets forth a reconciliation of changes in the fair value of allocated derivative assets and liabilities classified as Level 3 in the fair value hierarchy:

	Significant Unobservable Inputs (Level 3)
	Year Ended December 31,
	2010			2011			2012
	(in thousands)
Beginning balance	$	—		$	(1,108	)	$	(1,198	)
Realized gains (losses)		768			(1,130	)		5,965
Unrealized gains (losses)		(1,108	)		(90	)		1,086
Settlements paid (received)		(768	)		1,130			(5,965	)

Ending balance	$	(1,108	)	$	(1,198	)	$	(112	)

Change in unrealized gains (losses) included in earnings related to derivatives still held at period end	$	(1,108	)	$	(90	)	$	(112	)

8. Income Taxes

The provision (benefit) for income taxes for the years ended December 31, 2011 and 2012 was computed as if the Partnership Properties were a separate taxpayer and is comprised of (in thousands):

	2011			2012
Current	$	172		$	102
Deferred recognized at date the Partnership Properties became owned by a taxable entity		10,499			―
Deferred as a result of current operations		(169	)		1,694
Provision for income taxes	$	10,502		$	1,796

The provision for income taxes differs from the amount computed by applying the statutory federal income tax rate to income before provision for income taxes. The sources and tax effects of the differences for the years ended December 31, 2011 and 2012 are as follows (in thousands):

	2011			2012
Income tax expense at the federal statutory rate (35%)	$	3,299		$	1,717
Income tax expense not provided on net income prior to August 12, 2011 (when the Partnership Properties became owned by a taxable entity)		(3,273	)		―
State income tax expense (benefit)		(23	)		79
Basis difference on August 12, 2011 (when the Partnership Properties became owned by a taxable entity)		10,499			―
Income tax provision	$	10,502		$	1,796

Deferred income taxes reflect the net tax effects of temporary difference between carrying amounts of assets and liabilities for financial reporting purposes and their income tax bases.

Significant components of the Partnership Properties’ deferred tax assets and liabilities at December 31, 2011 and 2012 are as follows (in thousands):

	2011			2012
Deferred tax liabilities:
Current:
Derivative assets	$	441		$	10
Total current deferred tax liability		441			10
Noncurrent:
Derivative assets		244			―
Depreciable, depletable property, plant and equipment		13,972			17,790
Total noncurrent deferred tax liabilities		14,216			17,790
Total deferred tax liabilities		14,657			17,800

Deferred tax assets:
Current:
Derivative obligations		(572	)		(18	)
Stock compensation		(1,739	)		(1,673	)
Total current deferred tax assets		(2,311	)		(1,691	)
Noncurrent:
Derivative obligations		(579	)		(42	)
NOL and AMT credit carryforwards		(888	)		(3,347	)
Asset retirement obligations		(549	)		(587	)
Other assets		―			(109	)
Total noncurrent deferred tax assets		(2,016	)		(4,085	)
Total deferred tax assets		(4,327	)		(5,776	)
Net deferred tax liability	$	10,330		$	12,024

9. Stock-Based Compensation

On August 18, 2011, New Source granted 2,900,000 shares of restricted common stock, with 1,000,000 shares vesting upon the first anniversary of the date of grant, 700,000 shares vesting on the second anniversary of the date of grant, and the remaining 1,200,000 shares vesting on the completion of an initial public offering of NSE’s common stock pursuant to a filed prospectus provided that the employees remain employed by NSE on the applicable vesting dates subject to limited exceptions.

These financial statements reflect an allocated amount of stock-based compensation based on the total production of the Partnership Properties compared to total NSE production. Stock-based compensation expense is the result of the amortization of the value to expense over the vesting periods for which there are fixed vesting terms of the awards. Accordingly, the Partnership Properties recorded $4.5 million and $8.2 million of stock-based compensation for the years ended December 31, 2011 and 2012, respectively. As of December 31, 2012, unamortized stock compensation expense at New Source is $2.2 million.

10. Commitments and Contingencies

Legal Matters

New Dominion is a defendant in a legal proceeding arising in the normal course of its business which may impact the Partnership Properties 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, the plaintiffs would look to the working interest owners to pay their proportionate share of any liability. While the outcome and impact on the Partnership Properties 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 Properties 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 Properties are a party or to which any of their assets are subject.

11. Subsequent Events

Initial Public Offering

On February 13, 2013, NSLP completed its initial public offering (the “Offering”) of 4,000,000 common units representing limited partner interests in NSLP at a price to the public of $20.00 per common unit ($18.70 per common unit, net of underwriting discounts). NSLP received net proceeds of approximately $74.4 million from the Offering, after deducting underwriting discounts and incurred structuring fees, fees and expenses associated with our new revolving credit facility and offering expenses of approximately $2.8 million. NSLP assumed approximately $70.0 million of New Source Energy’s indebtedness previously secured by the Partnership 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. NSLP also borrowed $15.0 million of borrowings under a new revolving credit facility on February 13, 2013. NSLP made a cash distribution of $15.8 million to New Source Energy Corporation, a Delaware corporation (“New Source Energy”) as consideration (together with our issuance to New Source Energy of 777,500 common units, 2,205,000 subordinated units and a $25.0 million note payable) for the contribution by New Source Energy of the Partnership Properties and the commodity derivative contracts.

On March 12, 2013, NSLP received net proceeds of $4.7 million from the exercise of over allotment options from certain underwriters. 250,000 common units were issued representing limited partner interests in NSLP at a price of $20.00 less the underwriting discount ($18.70 per common unit, net).

Omnibus Agreement

On February 13, 2013, in connection with the closing of the Offering, NSLP entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among NSLP, New Source Energy GP, LLC, a Delaware limited liability company and the general partner of NSLP (the “General Partner”).

Pursuant to the Omnibus Agreement, New Source Energy will provide management and administrative services for NSLP and the General Partner. From the closing of the Offering through December 31, 2013, NSLP will pay New Source Energy a quarterly fee of $675,000 for the provision of such services. After December 31, 2013, in lieu of the quarterly fee, the 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 NSLP will reimburse the General Partner for such payments it makes to New Source Energy.

Additionally, pursuant to the Omnibus Agreement, New Source Energy will indemnify NSLP, with respect to the Partnership Properties against (i) title defects, subject to a $15,000 per claim de minimis exception, for amounts in excess of a $200,000 aggregate threshold, (ii) income taxes attributable to pre-closing operations as of the closing date of the Offering (iii) environmental claims, losses and expenses associated with the operation of our business prior to the closing, and (iv) all liabilities other than covered environmental liabilities, relating to the operation of the contributed assets prior to the closing that were not disclosed in the most recent pro forma balance sheet included in the Prospectus, or incurred in the ordinary course of business thereafter. New Source Energy’s maximum obligation under these indemnification provisions is limited to $2.0 million in the aggregate. New Source Energy’s indemnification obligation will (i) survive for three years after the closing of the Offering with respect to title, (ii) survive for one year after the closing of the Offering with respect to environmental and other operating liabilities and (iii) terminate upon the expiration of the applicable statute of limitations with respect to income taxes. NSLP will also indemnify New Source Energy against certain potential environmental claims, losses and expenses associated with the operation of the Partnership Properties that arise after the consummation of the Offering.

Credit Agreement

On February 13, 2013, in connection with the closing of the Offering, NSLP entered into a Credit Agreement (the “Credit Agreement”) by and among NSLP, 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, $60 million senior secured revolving credit facility with an initial borrowing base of $30 million. The borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to the estimated oil and gas reserves of NSLP 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. Unanimous approval by the lenders is required for any increase to the borrowing base. The Credit Agreement is available for working capital for exploration and production, to provide funds in connection with NSLP’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.

Borrowings under the Credit Agreement bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) the Administrative Agent’s prime rate or (c) LIBOR plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base will be subject to a commitment fee of 0.50% per annum. Accrued interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans, at shorter intervals.

Borrowings under the Credit Agreement are secured by liens on substantially all of NSLP’s properties, including, not less than (i) 80% of the total value of NSLP’s proved oil and gas properties, and (ii) 90% of the total value of NSLP’s proved, developed, producing oil and gas properties and guaranteed by New Source Energy.

The Credit Agreement requires NSLP to maintain a ratio of EBITDAX (earnings before interest, depletion depreciation and amortization, and income taxes) to Interest Expense of not less than 2.5 to 1.0, a ratio of Total Debt to EBITDAX of not more than 3.5 to 1.0 and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the Credit Agreement.

Additionally, the Credit Agreement contains various covenants and restrictive provisions that, among other things, limits the ability of NSLP to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. Notwithstanding the foregoing, the Credit Agreement permits NSLP to make distributions to its common unit holders in an amount not to exceed “Available Cash” (as defined in NSLP’s limited partnership agreement) so long as (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the Credit Agreement does not exceed 90%.

Events of default under the Credit Agreement include, but are not limited to, the failure to make payments when due, breach of any covenants continuing beyond the cure period, default under other material debt, change in management or change of control and bankruptcy or other insolvency events.

Assignment and Assumption Agreement

On February 13, 2013, in connection with the closing of the Offering, NSLP entered into an assignment and assumption agreement (the “Assignment and Assumption Agreement”) by and among NSLP and New Source Energy, pursuant to which New Source Energy assigned certain of its interests and rights under the Golden Lane Participation Agreement (the “Participation Agreement”) dated as of January 10, 2007, as amended by Amendment No. 1 to the Participation Agreement, dated as of October 20, 2007, which governs the development and operation of certain properties in the Golden Lane field, including the Partnership Properties. Pursuant to the Assignment and Assumption Agreement, NSLP became a party to the Participation Agreement.

100

The Golden Lane Participation Agreement requires us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. The Golden Lane Participation Agreement contains significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements. If a party declines to participate in a new well that New Dominion proposes, such party will not be eligible to participate in the next four wells in adjacent drilling and spacing units to such proposed well (unless the proposed well is in an undrilled township and range, in which case such party will not be eligible to participate in the next eight wells in adjacent drilling and spacing units to the proposed well), and such party also would be obligated to pay for its share of the applicable acquisition costs associated with the leasehold interests underlying the proposed new well even though it has elected not to participate in the well and the associated costs themselves. In addition, if a party declines to participate in a new well that New Dominion proposes, such party will relinquish its interest in the new well and its share of production from the new well until such time at which the proceeds from such relinquished interest paid to the working interest owners that elected to participate in the new well reach specified aggregate thresholds intended to compensate the parties for the election not to participate. The Golden Lane Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs within 30 days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs later.

Development Agreement

On February 13, 2013, in connection with the closing of the Offering, NSLP entered into a development agreement (the “Development Agreement”) by and among NSLP, New Source Energy and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, NSLP has agreed to maintain an average annual maintenance drilling budget of $8.2 million to drill certain of NSLP’s proved undeveloped locations and maintain NSLP’s producing wells.

Pursuant to the Development Agreement, the General Partner will, at least annually, at its discretion, determine NSLP’s maintenance drilling budget. The General Partner will also have the right to propose which wells are drilled based on NSLP’s maintenance drilling budget. Under the Development Agreement, New Dominion will use its commercially reasonable best efforts to (i) conduct its operations such that NSLP’s proportionate share of capital expenses that it would consider maintenance capital under the Participation Agreement is equal to the annual maintenance drilling budget set by the General Partner and (ii) cause the wells drilled pursuant to the Participation Agreement to be consistent with the maintenance drilling schedule proposed by the General Partner. The General Partner will also have the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.

Subordinated Promissory Note

On February 13, 2013, in connection with the closing of the Offering, NSLP issued a $25.0 million note payable (the “Note Payable”) to New Source Energy as partial consideration for its contribution of the Partnership Properties to NSLP. The Note Payable will mature on February 13, 2018 and will bear interest payable quarterly at a rate of LIBOR plus 2.50%. If, upon any interest payment date, NSLP does not have a minimum of $20.0 million of borrowing availability under the Credit Agreement, the amount of such interest payment will be capitalized and added to the outstanding principal amount of the Note Payable. The Note Payable is subordinated to borrowings under the Credit Agreement and any other senior indebtedness NSLP may incur in the future. NSLP will be permitted to prepay the Note Payable (plus accrued and unpaid interest) at any time; so long as, after giving effect to such prepayment, NSLP has a minimum of $20.0 million of borrowing availability under the Credit Agreement. On February 28, 2013, this note was paid in full with borrowings under the NSLP credit facility.

Contribution Agreement

On February 13, 2013, in connection with the closing of the Offering, NSLP entered into a Contribution, Conveyance and Assumption Agreement (the “Contribution Agreement”) by and among NSLP, the General Partner and New Source Energy, pursuant to which, among other things, New Source Energy contributed the Partnership Properties to NSLP, 2.0% of which contribution (the “GP Contribution”) was made by New Source Energy on behalf of the General Partner, in exchange for (i) 2,205,000 subordinated units, (ii) 777,500 common units, (iii) a $15.8 million cash payment, (iv) the Note Payable and (v) NSLP’s assumption of $70.0 million of New Source Energy’s existing indebtedness and NSLP’s agreement to pay such indebtedness immediately following New Source Energy’s contribution of the Partnership Properties to NSLP. Additionally, the General Partner received its prior 2.0% general partner interest in NSLP, represented by 150,000 general partner units, and all of NSLP’s incentive distribution rights.

Credit Agreement amendment and repayment of subordinated note

On February 28, 2013, NSLP entered into a First Amendment (the “First Amendment”) to its Credit Agreement, dated as of February 13, 2013, by and among NSLP, 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”).

101

The First Amendment (i) adds a lender under the Credit Agreement, (ii) increases NSLP’s borrowing base under the Credit Agreement from $30 million to $60 million, (iii) increases the lenders’ aggregate commitment under the Credit Agreement from $60 million to $150 million and (iv) removes references and provisions related to the $25.0 million subordinated promissory note (the “Subordinated Note”) issued by NSLP to New Source Energy Corporation in connection with the Offering. As a condition precedent to effectiveness of the First Amendment, NSLP repaid the Subordinated Note in full.

Acquisition of Properties from New Source Energy and Other Parties

On March 29, 2013, NSLP entered into a Contribution Agreement between NSLP and New Source Energy, pursuant to which, New Source Energy contributed the certain producing and undeveloped oil and gas properties in the Luther field in Oklahoma to NSLP in exchange for 348,000 common units. On March 29, 2013, NSLP entered into a Contribution Agreement between NSLP and Scintilla, LLC, pursuant to which, New Source Energy contributed the certain producing and undeveloped oil and gas properties in the Golden Lane and Luther fields in Oklahoma to NSLP in exchange for 976,500 common units. On March 29, 2013, NSLP entered into a Contribution Agreement between NSLP and W.K. Chernicky, LLC, pursuant to which, New Source Energy contributed the certain producing and undeveloped oil and gas properties in the Golden Lane and Luther fields in Oklahoma to NSLP in exchange for 54,000 common units.

The management of New Source has evaluated events and transactions associated with the Partnership Properties’ business after the balance sheet date through April 1, 2013, the date these financial statements were issued.

102

Unaudited Supplementary Information

Supplemental Oil and Natural Gas Information (unaudited)

Information with respect to oil and natural gas producing activities is presented in the following tables. Estimates of reserve quantities were determined by an independent petroleum engineering firm as of December 31, 2010, 2011 and 2012, and all of this information is unaudited.

Oil and natural gas properties

	December 31,
	2010			2011			2012
	(in thousands)
Proved	$	169,273		$	190,914		$	202,795
Less: accumulated depreciation, depletion and amortization		(83,224	)		(97,962	)		(112,372	)
Net capitalized costs for oil and natural gas properties	$	86,049		$	92,952		$	90,423

Costs incurred for oil and natural gas producing activities

Costs incurred for oil and natural gas producing activities during the years ended December 31, 2010, 2011 and 2012, consisted of developmental expenditures of $20.1 million, $21.1 million and $11.4 million, respectively.

Reserve quantity information

The following information represents estimates of proved reserves as of December 31, 2010, 2011 and 2012. The pricing used for estimates of reserves as of December 31, 2010, 2011, and 2012 was based on an unweighted twelve-month average West Texas Intermediate posted price of $79.53, $96.19 and $95.89, respectively, per Bbl for oil and a Henry Hub spot natural gas price of $4.39, $4.12 and $2.74, respectively, per Mcf for natural gas. Natural gas liquids were priced at 50%, 52%, and 36% of the oil prices for the periods ended December 31, 2010, 2011 and 2012, respectively, which approximates the realizable value received.

The Partnership Properties are all located in the United States, exclusively in the Hunton formation in east-central Oklahoma. The estimates of proved reserves associated with the Partnership Properties at December 31, 2010, 2011 and 2012 are based on reports prepared by independent reserve engineers Ralph E. Davis Associates, Inc. Proved reserves for all periods presented were estimated in accordance with the guidelines established by the SEC and the FASB.

The following table summarizes the prices utilized in the reserve estimates as of December 31, 2010, 2011 and 2012 as adjusted for location, grade and quality:

	December 31,
	2010		2011		2012
Oil	$	75.53	$	92.95	$	92.74
Gas	$	4.15	$	3.84	$	2.59
Liquids	$	37.76	$	48.33	$	33.39

Oil and natural gas reserve quantity estimates are subject to 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. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

Results of subsequent drilling, testing, and production may cause either upward or downward revisions of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. Reserve estimates are inherently imprecise and the estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

103

The following table provides a rollforward of the total net proved reserves for the years ended December 31, 2010, 2011 and 2012, as well as proved developed and proved undeveloped reserves at the end of each respective year. Oil and liquids volumes are expressed in Bbls and natural gas volumes are expressed in Mcf.

	Oil (Bbls)			Natural Gas (Mcf)			Liquids (Bbls)			Total (Boe)(1)
Total proved reserves
Balance, January 1, 2010		332,130			27,305,810			7,115,050			11,998,148
Revisions(2)		(87,879	)		(16,847,708	)		(667,557	)		(3,563,386	)
Extensions and discoveries(4)		110,080			13,467,750			1,698,770			4,053,475
Production		(68,071	)		(2,376,592	)		(658,293	)		(1,122,463	)
Balance, December 31, 2010		286,260			21,549,260			7,487,970			11,365,774

Proved developed reserves		151,170			13,417,740			5,450,030			7,837,490
Proved undeveloped reserves		135,090			8,131,520			2,037,940			3,528,283
Total proved reserves		286,260			21,549,260			7,487,970			11,365,773

Balance, January 1, 2011		286,260			21,549,260			7,487,970			11,365,773
Revisions(3)		88,170			(4,568,868	)		(562,175	)		(1,235,483	)
Extensions and discoveries(4)		627,770			7,003,650			3,102,760			4,897,805
Production		(48,770	)		(2,378,232	)		(720,615	)		(1,165,757	)
Balance, December 31, 2011		953,430			21,605,810			9,307,940			13,862,338

Proved developed reserves		276,240			11,125,330			5,323,650			7,454,112
Proved undeveloped reserves		677,190			10,480,480			3,984,290			6,408,227
Total proved reserves		953,430			21,605,810			9,307,940			13,862,339

Balance, January 1, 2012		953,430			21,605,810			9,307,940			13,862,339
Revisions		(469,630	)		1,295,502			57,825			(195,888	)
Extensions and discoveries(4)		106,400			3,512,130			1,049,350			1,741,105
Production		(61,010	)		(2,278,342	)		(711,195	)		(1,151,929	)
Balance, December 31, 2012		529,190			24,135,100			9,703,920			14,255,627

Proved developed reserves		249,140			11,980,390			6,182,620			8,428,492
Proved undeveloped reserves		280,050			12,154,710			3,521,300			5,827,135
Total proved reserves		529,190			24,135,100			9,703,920			14,255,627

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

(2)

The revisions in proved reserves in 2010 were largely due to a more detailed mapping process undertaken in 2010 whereby proved undeveloped reserves were reduced to reflect more closely the offset performance. Also, areas where proved developed well performance was not strong during 2010 resulted in several proved undeveloped locations being removed from the previous proved undeveloped category.

(3)	The revisions in proved reserves in 2011 were due to revisions to the proved developed producing forecasts subsequent to the acquisition of these assets from Scintilla, to more closely match the historical production performance.

(4)	Extensions and discoveries are due to development drilling in the Golden Lane area.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows is computed by applying the twelve-month unweighted average of the first-day-of-the-month pricing for oil and natural gas to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.

104

Discounted future cash flow estimates like those shown herein are not intended to represent estimates of the fair value of the Company’s oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs, and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following table provides the standardized measure of discounted future net cash flows as of December 31, 2010, 2011 and 2012:

	December 31,
	2010			2011			2012
	(in thousands)
Future production revenues	$	393,150		$	621,378		$	435,670
Future costs:
Production		(99,411	)		(138,297	)		(121,541	)
Development		(77,887	)		(86,630	)		(52,032	)
Income tax expense		—			(132,758	)		(85,090	)
10% annual discount for estimated timing of cash flows		(86,521	)		(110,360	)		(82,746	)
Standardized measure of discounted net cash flows(1)	$	129,331		$	153,333		$	94,261

(1)

Amounts do not include the effects of income taxes on future net revenues for 2010 because the properties were held by a limited liability company not subject to entity-level taxation as of December 31, 2010. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income is passed through to the equity holders of such limited liability company. Our standardized measure as of December 31, 2011 and 2012 includes effects of income taxes. The Partnership will not be a taxable entity. Removing income taxes from standardized measure as of December 31, 2012 would result in a pro forma standardized measure of $141 million.

Changes in standardized measure of discounted future net cash flows

The following table provides a rollforward of the standardized measure of discounted future net cash flows for the years ended December 31, 2010, 2011 and 2012:

	December 31,
	2010			2011			2012
	(in thousands)
Discounted future net cash flows at beginning of year	$	135,417		$	129,331		$	153,333
Increase (decrease)
Sales and transfers, net of production costs		(29,939	)		(36,230	)		(28,235	)
Net changes in prices and production costs		30,601			56,858			(93,618	)
Extensions and discoveries		57,276			75,830			8,688
Changes in future development costs		(36,631	)		(27,895	)		8,350
Previous development costs incurred		20,136			22,657			11,382
Revisions of previous quantity estimates		(50,351	)		(19,128	)		(5,833	)
Changes in income taxes		—			(80,919	)		33,532
Timing and other		(10,720	)		19,896			(8,671	)
Accretion of discount		13,542			12,933			15,333
Net increase (decrease)		(6,086	)		24,002			(59,072	)
Discounted future net cash flows at end of year	$	129,331		$	153,333		$	94,261

105

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Partners of New Source Energy Partners L.P.

Oklahoma City, Oklahoma

We have audited the accompanying balance sheet of New Source Energy Partners L.P. (the “Company”) as of December 31, 2012. This balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of the Company as of December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Houston, Texas

April 1, 2013

106

New Source Energy Partners L.P.

Balance Sheet as of December 31, 2012

ASSETS
Total assets	$	―

OWNERS’ EQUITY
General partner interest	$	20
Limited partner interest		980
Receivable from partners		(1,000	)
Total partners’ capital	$	―

The accompanying notes are an integral part of this financial statement.

107

New Source Energy Partners L.P.

Notes to Balance Sheet

(1) Organization and basis of presentation

Organization

New Source Energy Partners L.P. (NSLP) was organized pursuant to the laws of the State of Delaware on October 2, 2012 for the purpose of acquiring and developing oil and natural gas interests.

Basis of presentation

This balance sheet is presented in conformity with generally accepted accounting principles. Statements of operations, equity, and cash flows have not been presented because NSLP has had no business transactions or activities as of December 31, 2012.

(2) Subsequent Events

Initial Public Offering

On February 13, 2013, NSLP completed its initial public offering (the “Offering”) of 4,000,000 common units representing limited partner interests in NSLP at a price to the public of $20.00 per common unit ($18.70 per common unit, net of underwriting discounts). NSLP received net proceeds of approximately $74.4 million from the Offering, after deducting underwriting discounts and incurred structuring fees, fees and expenses associated with our new revolving credit facility and offering expenses of approximately $2.8 million. NSLP assumed approximately $70.0 million of New Source Energy’s indebtedness previously secured by certain oil and gas properties contributed to NSLP by New Source Energy (the “Partnership 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. NSLP also borrowed $15.0 million of borrowings under a new revolving credit facility on February 13, 2013. NSLP made a cash distribution of $15.8 million to Source Energy Corporation, a Delaware corporation (“New Source Energy”) as consideration (together with our issuance to New Source Energy of 777,500 common units, 2,205,000 subordinated units and a $25.0 million note payable) for the contribution by New Source Energy of the Partnership Properties and the commodity derivative contracts.

Omnibus Agreement

108

Credit Agreement

Assignment and Assumption Agreement

109

The Golden Lane Participation Agreement controls the development and operation of the Golden Lane field and provides New Dominion, LLC, an Oklahoma limited liability company (“New Dominion”), as operator, with authority to control the development and operation of the field. New Dominion’s control rights are subject to its agreement to use its commercially reasonable efforts to conduct its operations in a manner consistent with the development agreement described below. New Dominion is empowered to acquire additional leasehold within the Golden Lane field for the account of the working interest owners in exchange for a turnkey fee per net acre acquired. This turnkey fee is currently $300 per net acre acquired and may be increased by New Dominion from time to time in the event of an increase in prevailing leasehold acquisition costs. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold for a turnkey acreage fee then applicable under the Golden Lane Participation Agreement until development has commenced. Each party to the Golden Lane Participation Agreement has committed to participate in future wells proposed by the operator for its proportionate share of the costs associated with such wells. The parties also have agreed to pay New Dominion their proportionate shares of an initial connection charge of $300,000 per well in the Golden Lane field, subject to increase in certain circumstances, for connection and access to its saltwater disposal infrastructure within the Golden Lane field and also to pay New Dominion their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

The Golden Lane Participation Agreement requires us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. The Golden Lane Participation Agreement contains significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements. If a party declines to participate in a new well that New Dominion proposes, such party will not be eligible to participate in the next four wells in adjacent drilling and spacing units to such proposed well (unless the proposed well is in an undrilled township and range, in which case such party will not be eligible to participate in the next eight wells in adjacent drilling and spacing units to the proposed well), and such party also would be obligated to pay for its share of the applicable acquisition costs associated with the leasehold interests underlying the proposed new well even though it has elected not to participate in the well and the associated costs themselves. In addition, if a party declines to participate in a new well that New Dominion proposes, such party will relinquish its interest in the new well and its share of production from the new well until such time at which the proceeds from such relinquished interest paid to the working interest owners that elected to participate in the new well reach specified aggregate thresholds intended to compensate the parties for the election not to participate. The Golden Lane Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs within 30 days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs later.

Development Agreement

110

Subordinated Promissory Note

Contribution Agreement

Credit Agreement amendment and repayment of subordinated note

The First Amendment (i) adds a lender under the Credit Agreement, (ii) increases NSLP’s borrowing base under the Credit Agreement from $30 million to $60 million, (iii) increases the lenders’ aggregate commitment under the Credit Agreement from $60 million to $150 million and (iv) removes references and provisions related to the $25.0 million subordinated promissory note (the “Subordinated Note”) issued by NSLP to New Source Energy Corporation in connection with NSLP’s initial public offering. As a condition precedent to effectiveness of the First Amendment, NSLP repaid the Subordinated Note in full.

Acquisition of Properties from New Source Energy and Other Parties

Subsequent events have been evaluated through April 1, 2013, which is the date the financial statements were issued.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.

CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures.

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including the principal executive officer and principal financial officer of our general partner, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act) as of the end of the period covered by this annual report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2012.

Management’s Report on Internal Control Over Financial Reporting

This annual report does not include management's assessment regarding internal control over financial reporting due to a transition period established by rules of the SEC for newly public companies.

Attestation Report of the Registered Public Accounting Firm

This Report does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Remediation of Material Weaknesses in Internal Control Over Financial Reporting

During the year ended December 31, 2012, our management completed corrective actions to remediate certain of the material weaknesses identified in our Registration Statement on Form S-1. Specifically, the following actions were taken with respect to the following identified material weaknesses:

· The Company did not maintain effective controls over accounting for depreciation, depletion and amortization expense attributable to time periods in which its oil and natural gas properties were owned by Scintilla. New Source Energy evaluated its historical financial and operations data for further deficiencies and has changed the method by which it computes its natural gas and NGL sales volumes to ensure that such volumes match the actual volumes processed by its first purchasers.

· The Company did not maintain effective controls over accounting for non-recurring transactions relating to acquisitions. New Source Energy also instituted additional control procedures around the research and recording of nonrecurring transactions, including engaging an accounting firm to assist us in accounting and reporting for non-recurring transactions.

Changes in Internal Control Over Financial Reporting

Other than as described above, there have not been any other changes in our internal control over financial reporting during the quarter ended December 31, 2012, which have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B.

OTHER INFORMATION

None.

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PART III.

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of New Source Energy Partners L.P.

New Source Energy GP, LLC, our general partner, manages our operations and activities on our behalf. Our general partner is owned 5.6% by New Source Energy, 25% by an entity controlled by Mr. Chernicky, the Chairman of our general partner, and 69.4% by an entity controlled by Mr. Kos, the President and Chief Executive Officer of our general partner. All of our executive management personnel are employees of New Source Energy, and devote their time as needed to conduct our business and affairs.

Our general partner has a board of directors that oversees its management, operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation.

Our general partner owes a fiduciary duty to our unitholders. However, our partnership agreement contains provisions that reduce the fiduciary duties that our general partner owes to our unitholders. Our general partner is liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, our general partner intends to cause us to incur indebtedness or other obligations that are nonrecourse to it. Except for limited circumstances under our partnership agreement, and subject to its fiduciary duty to act in good faith, our general partner will have exclusive management power over our business and affairs.

Board Leadership Structure and Role in Risk Oversight

Leadership of our general partner’s board of directors is vested in a Chairman of the Board. Although our Chief Executive Officer currently does not serve as Chairman of the board of directors of our general partner, we currently have no policy prohibiting our current or any future chief executive officer from serving as Chairman of the Board. The board of directors, in recognizing the importance of the board of directors having the ability to operate independently, determined that separating the roles of Chairman of the Board and Chief Executive Officer is advantageous for us and our unitholders. Our general partner’s board of directors has also determined that having the Chief Executive Officer serve as a director enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations, and ultimately improves the ability of the board of directors to perform its oversight role.

The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise-level risk management, while retaining responsibility for oversight of our executive officers in that regard. Our executive officers will offer an enterprise-level risk assessment to the board of directors at least once every year.

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Directors and Executive Officers

The following table sets forth certain information regarding the current directors and executive officers of our general partner.

Name	Age	Position
David J. Chernicky	59	Chairman of the Board and Senior Geologist
Kristian B. Kos	35	Director, President and Chief Executive Officer
Richard D. Finley	62	Chief Financial Officer and Treasurer
Carol T. Bryant	55	Senior Engineer
Terry L. Toole	68	Director
V. Bruce Thompson	65	Director
Phil Albert	53	Director

Our general partner’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. In selecting and appointing directors to the board of directors, the owners of our general partner do not intend to apply a formal diversity policy or set of guidelines. However, when appointing new directors, the owners of our general partner will consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board of directors as a whole.

David J. Chernicky—Chairman and Senior Geologist—David J. Chernicky was appointed Chairman of the Board and Senior Geologist of our general partner in October 2012. Mr. Chernicky has also served as the chairman of the board and senior geologist of New Source Energy since August 2011 and has more than 31 years of experience in the oil and gas industry. On July 1, 1998, Mr. Chernicky co-founded New Dominion, an oil and gas exploration and production company based in Tulsa, Oklahoma. Mr. Chernicky beneficially owns New Dominion and Scintilla. From April 2002 until his resignation on August 1, 2011, Mr. Chernicky served as the president and manager of Scintilla and New Dominion, overseeing those companies’ operations as a whole. Mr. Chernicky currently serves on the boards of various governmental bodies, including the Grand River Dam Authority (“GRDA”) and the Oklahoma Ordinance Works Authority. Prior to founding New Dominion, Mr. Chernicky was employed in 1979 as a geologist for Marathon Oil in Casper, Wyoming and later, from 1979 until 1983 as a geologist and geophysicist for Amoco Production in Denver, Colorado. Thereafter, Mr. Chernicky worked as an independent consulting geologist until founding New Dominion, LLC. Mr. Chernicky graduated from the University of Oklahoma in 1978 with a Bachelor of Science degree in exploration geophysics. We believe Mr. Chernicky’s extensive experience in the oil and gas industry, his leadership positions at other oil and gas companies, his reservoir engineering skills and his knowledge regarding our business and operations brings important experience and leadership to the board of directors.

Kristian B. Kos—President and Chief Executive Officer—Kristian B. Kos was appointed President and Chief Executive Officer of our general partner in October 2012. Mr. Kos has also served as the president and chief executive officer and director of New Source Energy since July 2011 and has been involved in oil and gas and energy industries since 2005. From May 2010 through July 2011, Mr. Kos provided consulting services to New Dominion. In August 2006, Mr. Kos founded Deylau, LLC, a company focused on identifying, managing and financing oil and gas production companies, and served as its manager from August 2006 to July 2011. From February 2006 to February 2007, Mr. Kos served as a Vice President at Diamondback Energy Services, where he was actively involved in identifying and executing growth strategies for that company, including acquisitions. From September 2005 to February 2006, Mr. Kos worked in a business-development role for Gulfport Energy. Prior to working in the oil and gas and energy sectors, Mr. Kos worked in the financial sector for hedge fund manager Wexford Capital LP. Mr. Kos currently serves as a director and, through Deylau, is the majority stockholder of Encompass Energy Services, Inc. Mr. Kos earned Bachelor of Arts and Master of Arts degrees in Economics and Philosophy from Trinity College, Dublin, Ireland in 1999. He also earned a Master of Philosophy degree in Economics from the University of Aix-Marseille, France in 2000. We believe Mr. Kos’s experience in the financial and oil and gas industries, his leadership positions at other oil and gas companies, and his knowledge regarding our business and operations provides important experience and leadership to the board of directors.

Richard D. Finley—Chief Financial Officer and Treasurer—Richard D. Finley, C.P.A. was appointed Chief Financial Officer and Treasurer of our general partner in October 2012. Mr. Finley has also served as the chief financial officer and treasurer of New Source Energy since August 2011 and is a partner at Finley & Cook, PLLC, an Oklahoma certified public accounting firm. Mr. Finley transitioned out of his role as a partner at Finley & Cook, where he worked since 1973, overseeing tax and accounting services within various industries and business environments. Mr. Finley has extensive experience with oil and gas exploration and production clients in general matters of accounting and taxation. Mr. Finley earned a Bachelor degree in accounting from Central State University, Edmond, Oklahoma, in 1973. He has been a Certified Public Accountant since 1975 and is a member of both the Oklahoma Society of Certified Public Accountants and the American Institute of Certified Public Accountants. He is also a Certified Valuation Analyst and a member of the National Association of Certified Valuation Analysts.

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Carol T. Bryant—Senior Engineer—Carol T. Bryant was appointed Senior Engineer of our general partner in October 2012. Ms. Bryant has also served as the senior engineer for New Source Energy Corporation since August 2011. Prior to joining New Source Energy, Ms. Bryant was a consulting petroleum engineer for Pinnacle Energy Services from June 2008 to April 2011 where she prepared third party reserve and engineering reports for clients with assets in the Mid-Continent region. From April 2007 to May 2008, Ms. Bryant was the senior reservoir engineer for Windsor Energy Resources, LLC and Gulfport Energy/Grizzly Oil Sands, LLC, responsible for corporate reserve evaluation and database development, facilitating bank engineering reviews and investor reserve reporting. From May 2000 to April 2007, Ms. Bryant held various reservoir engineering positions with Chaparral Energy, LLC in Oklahoma City. She was the corporate reserve manager responsible for quarterly, year-end and special reporting requirements and facilitated third party and bank engineering reviews. She initiated organizational changes to meet the needs of a rapidly growing reserve base and in preparation to meet IPO reporting requirements and Sarbanes-Oxley compliance. As a senior reservoir engineer at Chaparral, Ms. Bryant developed geologic and reservoir simulation models to evaluate CO2 reserve potential for several Morrow CO2 floods in the Oklahoma and Texas panhandles. Prior to that, Ms. Bryant held positions as a production and reservoir engineer with various firms including Amoco Production Company in Denver, Colorado. Ms. Bryant graduated from the University of Tulsa in 1980 with a Bachelor of Science degree in Petroleum Engineering.

Terry L. Toole—Director—Terry L. Toole, C.P.A. was appointed to serve as a member of the board of directors of our general partner in October 2012. Mr. Toole served as a director of New Source Energy from January 2012 until January 2013. Mr. Toole serves on the conflicts committee of the board of directors of our general partner. Mr. Toole retired as a partner of Finley & Cook, PLLC, on November 1, 2010, where he had been employed since 1976. He has significant accounting experience with companies in the oil and natural gas industry, including several publicly traded exploration and production companies and drilling funds. At the time of Mr. Toole’s retirement from Finley & Cook, he chaired the firm’s audit and oil and gas accounting departments. Mr. Toole received a Bachelor of Science degree in Business Administration (concentration in Economics) from Fort Hays State University in Hays, Kansas in 1966 and a Master’s degree in Business Administration (concentration in Accounting) in 1968 from West Texas A&M University in Canyon, Texas. He has been a Certified Public Accountant since 1970 and is a member of both the Oklahoma Society of Certified Public Accountants and the American Institute of Certified Public Accountants. We believe Mr. Toole’s expertise as a Certified Public Accountant and his extensive knowledge relating to auditing and accounting matters pertinent to the oil and natural gas industry provide important experience to the board of directors.

V. Bruce Thompson—Director—Mr. V. Bruce Thompson was appointed to serve as a member of the board of directors of our general partner in October 2012. Mr. Thompson served as general counsel of New Source Energy from August 2011 to August 2012 and has served as secretary of New Source Energy since August 2011. Mr. Thompson also serves as President of The American Exploration & Production Council (AXPC), a Washington, D.C.-based trade association whose membership is composed of 31 of America’s leading independent oil and natural gas exploration and production companies, a position he has held since October 2008. From March 2007 to April 2008, Mr. Thompson served as senior vice president and general counsel of SandRidge Energy, Inc. (NYSE: SD). Additionally, from August 2003 to March 2007, Mr. Thompson served as senior counsel with Brownstein Hyatt Farber Schreck in the firm’s Washington, D.C. and Denver offices. Previously, Mr. Thompson served as senior vice president and general counsel of Forest Oil Corporation (NYSE: FST). Mr. Thompson also served as chief of staff for then Congressman, now U.S. Senator, James Inhofe. Mr. Thompson graduated from the University of Pennsylvania’s Wharton School of Business with a Bachelor of Science degree in Economics with an emphasis on corporate finance in 1969 and received his Juris Doctorate from the University of Tulsa’s College of Law in 1974. We believe Mr. Thompson’s previous experience as the general counsel of a public company provides him with a high level of technical expertise in reviewing transactions and agreements and addressing the myriad legal issues to be presented to the board of directors.

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Phil Albert—Director—Mr. Albert was appointed to serve as a member of the board of directors of our general partner in October 2012. Mr. Albert joined New Dominion in 2005 as Executive Vice President. In this position, Mr. Albert oversees operations for New Dominion, including fiscal and budgetary policies, personnel management, and has complete responsibility for strategic initiatives and investments. Before joining New Dominion in 2005, he worked at JEM Engineering in Tulsa for 21 years, serving in many leadership positions, including Controller, Treasurer, and Chief Financial Officer and finally President and Chief Operating Officer. Previously, he was an accountant and auditor for the consulting firm of Peat Marwick Mitchell, now known as KPMG. In addition to his responsibilities at New Dominion, he serves as President of Pelco Structural, LLC., a manufacturer of infrastructure products in Claremore, Oklahoma. He is a graduate of Oklahoma Baptist University in 1981 with a magna cum laude degree in accounting. Mr. Albert currently serves as member on Claremore Chamber of Commerce Board. Mr. Albert is the brother-in-law of Mr. Chernicky. Mr. Albert’s knowledge relating to auditing and accounting matters pertinent to the oil and natural gas industry provides important experience to the board of directors.

Committees of the Board of Directors

Audit Committee

Rules implemented by the NYSE and SEC require our general partner to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the completion of our IPO. Prior to the completion of our IPO, Mr. Toole was appointed the chairman and sole member of our audit committee. The board of directors has determined that Mr. Toole is financially literate, is the audit committee financial expert and is “independent” under the standards of the NYSE and SEC regulations currently in effect. The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee.

Conflicts Committee

Terry L. Toole currently serves as the sole member of our conflicts committee. The conflicts committee will determine if the resolution of any conflict of interest referred to it by our general partner is in the best interests of our partnership. Any matters approved by the conflicts committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act to file certain reports with the SEC and NYSE concerning beneficial ownership of such securities.

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Based solely on a review of the copies of reports on Form 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of New Source Energy GP, LLC, we believe that during the year ended December 31, 2012 the officers and directors of New Source Energy GP, LLC and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a).

Corporate Governance

The board of directors of our general partner has adopted a Financial Code of Ethics that applies to the chief executive officer, chief financial officer, controller, treasurer and all other persons performing similar functions on behalf of our general partner and us. Amendments to or waivers from the Financial Code of Ethics will be disclosed in accordance with the rules and regulations of the SEC and the listing requirements of the NYSE. The Board has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and its affiliates and us.

We make available free of charge, within the “Corporate Governance” section of our website at http://www.newsource.com/Investors/Corporate-Governance/default.aspx, the Financial Code of Ethics, the Corporate Governance Guidelines and the Code of Business Conduct and Ethics. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

ITEM 11.

EXECUTIVE COMPENSATION

Compensation Overview

Executive Summary

We and our general partner were formed in October of 2012. We are a new subsidiary formed to hold the Partnership Properties, which previously comprised a portion of the assets of New Source Energy. We do not currently employ any of the persons responsible for managing our business. All of the initial executive officers that will be responsible for managing our day to day affairs are also current executive officers of our parent New Source Energy. The individuals that are considered to be our “named executive officers” and which are also “named executive officers” at New Source Energy are as follows:

•

Kristian B. Kos - Chief Executive Officer and President

•

Richard D. Finley –Chief Financial Officer; and

•

David J. Chernicky – Senior Geologist

Compensation for the 2012 Fiscal Year

As noted above, neither we nor our general partner were formed until October of 2012, thus our general partner did not accrue any obligations with respect to executive compensation for its directors or executive officers for any period of time prior to its formation date. For the approximate two months of 2012 that we and our general partner were in existence, our named executive officers remained directly employed by New Source Energy and it was New Source Energy that made all compensation decisions and provided compensation payments to our named executive officers. Neither we nor New Source Energy considered the compensation that New Source Energy provided to the named executive officers to have been allocated to us at any time during the 2012 year.

Although New Source Energy did not allocate compensation costs to us in 2012, and we did not separately compensate our named executive officers for their services to us during the last two months of the 2012 year, our general partner appreciated that the efforts of our named executive officers during those two months were an integral part of our successful IPO. In recognition of those efforts, following the completion of our IPO, our general partner granted our named executive officers equity-based compensation awards pursuant to the New Source Energy Partners L.P. Long Term Incentive Plan, or “LTIP,” during February 2013, as more fully discussed below. Those awards will be disclosed as compensation to our named executive officers within any required compensation tables in our Form 10-K for the 2013 year.

Omnibus Agreement and Our Future Compensation Arrangements with New Source Energy

We did not have a formal agreement in place during the 2012 year with New Source Energy with respect to the compensation of New Source Energy employees that may have provided services to us in connection with our formation or our IPO. In connection with the closing of our IPO in February 2013, we entered into an omnibus agreement with New Source Energy, pursuant to which, among other things, New Source Energy will provide management and administrative services for us and our general partner. During the 2013 year, we will pay a set quarterly fee to New Source Energy for such services that will not be impacted by the amount of time that our named executive officers spend in performing services for us or for New Source Energy. Following the 2013 year, however, we will reimburse our general partner on a quarterly basis for actual expenses that it incurs in its performance under the omnibus agreement and for any payments that our general partner makes to New Source Energy.

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Responsibility and authority for compensation-related decisions for executive officers and other personnel that are employed by New Source Energy will continue to reside with New Source Energy. New Source Energy has the ultimate decision-making authority with respect to the total compensation of its employees, including the individuals that serve as our named executive officers, and (subject to the terms of the omnibus agreement) with respect to the portion of compensation that may become allocated to us in the future. Any such compensation decisions will not be subject to any approval by the board of directors of our general partner. Although we will bear the responsibility of providing the required fees to New Source Energy pursuant to the omnibus agreement for the compensation and benefits provided to the New Source Energy employees who provide services to us, we will have no control over such costs.

The employee compensation costs that are covered under the omnibus agreement do not include any costs associated with equity-based compensation awards that we may grant to individuals pursuant to our LTIP, or any cash compensation that we choose to pay to any New Source Energy employee directly and any such compensation maybe charged to NSLP accordingly. The LTIP was adopted by our general partner’s board of directors on January 30, 2013, and all decisions regarding awards under the LTIP will be made by our general partner’s board of directors or its delegates. Responsibility and authority for compensation-related decisions for personnel employed directly by our general partner, if any, will also reside with our general partner.

Long-Term Incentive Plan

On January 30, 2013, the board of directors of our general partner adopted the LTIP for the employees, officers, consultants and directors of us, our general partner, or any affiliate of either us or our general partner, including New Source Energy. The purpose of the LTIP is to provide a means to attract and retain individuals who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. The LTIP will provide grants of (1) restricted units (“Restricted Units”), (2) unit appreciation rights (“UARs”), (3) unit options (“Options”), (4) phantom units (“Phantom Units”), (5) unit awards (“Unit Awards”), (6) substitute awards, (7) other unit-based awards (“Unit-Based Awards”), (8) cash awards, (9) performance awards, and (10) distribution equivalent rights (“DERs”) (collectively referred to as “Awards”).

In February 2013, the board of directors of our general partner granted Restricted Unit Awards to certain eligible individuals under the LTIP, including our named executive officers. Each Restricted Unit Award agreement sets forth the number of Restricted Units each recipient is entitled to receive, subject to certain forfeiture restrictions and the applicable vesting schedules. Because the Restricted Unit Awards granted in February 2013 were so closely tied to the consummation of our IPO, the vesting schedule for these awards is tied the end of the subordination period for our common units as well as to the recipient’s continuous service to us or one of our affiliates during the subordination period. Each holder of a Restricted Unit will be entitled to receive quarterly distributions during any such restricted period, and if the vesting conditions are satisfied, the holder will receive unrestricted common units. Each Restricted Unit Award agreement provides for the forfeiture of the award in the event that the recipient is terminated for “cause,” which is generally defined as the recipient’s (i) willful engagement in dishonesty, illegal or gross misconduct; (ii) the recipient’s embezzlement, misappropriation or fraud; (ii) the recipient’s conviction of, or guilty or nolo contendere plea to, a crime or felony; or (iv) the recipient’s breach of fiduciary duties to the us or our affiliates. The vesting schedule in each Restricted Unit Award agreement shall be accelerated in the event that the recipient’s termination of services ends due to the recipient’s death, or upon the occurrence of a “change of control” (as defined below). In the event that the recipient’s termination of services occurs for any other reason, the restricted units will be eligible to continue vesting, subject to the recipient’s continued satisfaction of certain restrictive covenants contained within the participant’s award agreement.

The LTIP generally defines a “change in control” as the occurrence of one or more of the following events: (1) any person or group (other than us, our general partner, or an affiliate of either us or our general partner) becomes the beneficial owner of 50% or more of the voting power of the voting securities of us or our general partner; (2) our limited partners or the limited partners of our general partner approve a plan of complete liquidation of us or our general partner; (3) the sale or other disposition by us or our general partner of all or substantially all of its assets to any person that is not an affiliate; (4) our general partner or an affiliate of us or our general partner ceases to be our general partner; or (5) any other event that is specified as a “change in control” within any individual Award agreement.

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Our general partner granted Messrs. Kos, Finley and Chernicky Restricted Units in the amount of 133,750, 20,000 and 133,750, respectively, on February 13, 2013. Other key employees of our general partner, each of which are providing services to us, may also be granted awards pursuant to the LTIP from time to time.

DIRECTOR COMPENSATION

Due to the fact that we did not complete our IPO until the 2013 year, the non-employee members of the board of directors of our general partner did not receive any compensation during the 2012 year. For the portion of the 2013 year that follows the completion of our IPO, however, each of the non-employee members of the board of directors of our general partner will receive an annual retainer of $100,000, which may be paid in the form of cash, equity or some combination of cash and equity, at our general partner’s discretion. In the event that our general partner chooses to pay the annual retainer in the form of equity, such common units will be granted pursuant to the LTIP. The non-employee directors will also be compensated for their time spent serving on committees or for completing special projects, pursuant to an hourly rate fee arrangement. For the 2013 year, that hourly rate will be $200.

In addition to the compensation arrangement described above, the non-employee directors will also be eligible to receive awards pursuant to the LTIP from time to time, at our general partner’s discretion. Terry L. Toole, V. Bruce Thompson and Phil Albert also received Restricted Unit Awards in February 2013, in recognition for their efforts associated with our IPO, in the amount of 5,000, 5,000 and 12,500 units, respectively. The terms and conditions of these Restricted Unit Awards are substantially similar to those provided to our named executive officers and described above.

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Compensation Committee Interlocks and Insider Participation

As a limited partnership, we are not required by the NYSE to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future.

Compensation Committee Report

Neither we nor our general partner has a compensation committee. The board of directors of our general partner has reviewed and discussed the Compensation Overview set forth above and based on this review and discussion has approved it for inclusion in this Annual Report on Form 10-K.

The board of directors of New Source Energy GP, LLC:

David J. Chernicky

Kristian B. Kos

Terry L. Toole

V. Bruce Thompson

Phil Albert

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

As of March 29, 2013, the following table sets forth the beneficial ownership of our common and subordinated units that are owned by:

each person who then will beneficially own more than 5% of the then outstanding common units;

each director of our general partner;

each named executive officer of our general partner; and

all directors and named executive officers of our general partner as a group.

Name of Beneficial Owner(1)	Common Units to be Beneficially Owned		Percentage of Common Units to be Beneficially Owned			Subordinated Units to be Beneficially Owned		Percentage of Subordinated Units to be Beneficially Owned			Percentage of Total Common and Subordinated Units to be Beneficially Owned
New Source Energy Corporation (2)		1,125,500		16.6	%		2,205,000		100	%		37.1	%
David J. Chernicky (2)		2,235,750		33.0	%		2,205,000		100	%		49.5	%
Kristian B. Kos		133,750		2.0	%		–		–	%		1.5	%
Richard D. Finley		20,000		0.3	%		–		–	%		0.2	%
Terry L. Toole		5,000		0.1	%		–		–	%		0.1	%
V. Bruce Thompson		5,000		0.1	%		–		–	%		0.1	%
Phil Albert		12,500		0.2	%		–		–	%		0.1	%
All named executive officers and directors as a group (six persons) (2)		2,412,000		35.6	%		2,205,000		100	%		51.4	%

(1)	The address for all beneficial owners in this table is 914 North Broadway, Suite 230, Oklahoma City, Oklahoma 73102.

(2)

Mr. Chernicky is the Chairman and controlling shareholder of New Source Energy and may be deemed to beneficially own the units held by New Source Energy Corporation. In addition, Mr. Chernicky indirectly owns 967,500 common units held by Scintilla. Mr. Chernicky owns 100% of the outstanding membership interests in Scintilla. Mr. Chernicky disclaims beneficial ownership of units held by New Source Energy Corporation in excess of his pecuniary interest in New Source Energy Corporation.

Securities Authorized for Issuance Under Equity Compensation Plans

As discussed above, prior to the completion of our IPO, on January 30, 2013, the board of directors of our general partner adopted the LTIP for employees, officers, consultants and directors of our general partner and any of its affiliates, including New Source Energy, who perform services for us. The purpose of the LTIP is to provide a means to attract and retain individuals who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. Upon the closing of the IPO, on February 13, 2013, the board of directors of our general partner awarded a total of 367,500 restricted units to certain officers and directors of our general partner. No equity compensation plans have been approved by our unitholders.

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ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

New Source Energy owns approximately 16.6% of our outstanding common units and all of our subordinated units, and Mr. Chernicky also owns 1,110,250 of our outstanding common units. New Source Energy owns 5.6% of the membership interests in our general partner, an entity controlled by Mr. Chernicky owns 25% of the membership interests in our general partner and an entity controlled by Mr. Kos owns the remaining 69.4% of the membership interests in our general partner. As of March 29, 2013, our general partner owns a 2.0% general partner interest in us, evidenced by 155,102 general partner units, and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s-length negotiations.

Formation Stage

The consideration received by our general

partner and New Source Energy prior to or

in connection with our IPO

777,500 common units;

2,205,000 subordinated units;

155,102 general partner units;

all of our incentive distribution rights;

a $25.0 million note payable; and

approximately $15.8 million in cash.

The consideration received by New Source

Energy in connection with our acquisition

of additional properties

348,000 common units.

Operational Stage

Distributions of available cash to our

general partner and its affiliates

We will generally make cash distributions of 98.0% to our unitholders, including New Source Energy as the holder of approximately 39.2% of our limited partner interests, pro rata and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 25.0% of the distributions above the highest target distribution level, including the general partner’s 2.0% general partner interest.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $0.3 million on its general partner units and New Source Energy would receive an annual distribution of approximately $7.0 million on its common units and subordinated units.

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Payments to our general partner

and its affiliates

Pursuant to our omnibus agreement, New Source Energy provides management and administrative services for us and our general partner. Through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of such services. 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 we will reimburse our general partner for such payments it makes to New Source Energy. We are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit. New Source Energy will not be liable to us for its performance of, or failure to perform, services under this agreement unless there has been a final decision determining that New Source Energy acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

Withdrawal or removal of our general partner

If our general partner is removed under circumstances where cause exists or withdraws where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and the incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest in us and its incentive distribution rights for their fair market value or to convert such interests into common units.

Liquidation Stage

Liquidation

Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Related Party Agreements

We, our general partner and its affiliates entered into various documents and in connection with our IPO in February 2013 and the contribution of the Partnership Properties by New Source Energy to us. These agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s-length negotiations.

Golden Lane Participation Agreement

At the closing of our IPO, we acquired record title from New Source Energy to the leasehold interests that relate to the proved reserves detailed in our reserve report and we became a party to the Golden Lane Participation Agreement. The other parties to the Golden Lane Participation Agreement include New Dominion, as operator, New Source Energy and Scintilla, as continuing working interest owners, and a number of unaffiliated entities that also own working interests in the Golden Lane field.

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The Golden Lane Participation Agreement controls the development and operation of the Golden Lane field and provides New Dominion, as operator, with authority to control the development and operation of the field. New Dominion’s control rights are subject to its agreement to use its commercially reasonable efforts to conduct its operations in a manner consistent with the development agreement described below. New Dominion also is empowered to acquire additional leasehold within the Golden Lane field for the account of the working interest owners in exchange for a turnkey fee per net acre acquired. This turnkey fee is currently $300 per net acre acquired and may be increased by New Dominion from time to time in the event of an increase in prevailing leasehold acquisition costs. The Golden Lane Participation Agreement permits New Dominion to hold record title to any undeveloped leasehold within the Golden Lane area of mutual interest that it acquires in the future for the benefit of the parties to the Golden Lane Participation Agreement until such time as development of the applicable leasehold commences. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold for a turnkey acreage fee then applicable under the Golden Lane Participation Agreement until development has commenced. Although New Dominion would hold record title to any such undeveloped leasehold, the Golden Lane Participation Agreement requires the assignment to us of the leasehold when development commences, and it is this right on which we rely in connection with estimating any proved undeveloped reserves associated with such acreage hereafter acquired by New Dominion for our benefit in our future reserve reports. Each party to the Golden Lane Participation Agreement has committed to participate in future wells proposed by the operator for its proportionate share of the costs associated with such wells. The parties also have agreed to pay New Dominion their proportionate shares of an initial connection charge of $300,000 per well in the Golden Lane field, subject to increase in certain circumstances, for connection and access to its saltwater disposal infrastructure within the Golden Lane field and also to pay New Dominion their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

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Development Agreement

We are party to a development agreement with the New Source Group with respect to the drilling of our proved undeveloped reserves that comprise a portion of the Partnership Properties. Pursuant to the development agreement, during each of our fiscal years ending December 31, 2013 through December 31, 2016, we have agreed to maintain an average annual maintenance drilling budget of $8.2 million to drill certain of our proved undeveloped locations and maintain our producing wells. In connection with our entry into the development agreement, we became a party to the Golden Lane Participation Agreement. For a description of the Golden Lane Participation Agreement, please read “—Golden Lane Participation Agreement.”

While we have committed to establishing a maintenance drilling budget which provides that we spend an average of $8.2 million annually from 2013 through 2016 pursuant to the development agreement, we anticipate that our general partner will propose, not less than annually, additional growth capital expenditures and related drilling and development projects to grow our resources and production over time. We expect this growth to come through drilling additional proved undeveloped properties, increasing our working interests in wells through forced pooling and acquiring properties from both New Source Energy and third parties. The amount and timing of these growth capital expenditures will depend on both the amount of capital we have available to fund such expenditures as well as the success of our drilling program.

Pursuant to the development agreement, our general partner will, at least annually and likely more frequently, at its discretion, determine our maintenance drilling budget. Our general partner will also have the right to propose which wells are drilled based on our maintenance drilling budget. Under the development agreement, New Dominion will use its commercially reasonable best efforts to (i) conduct its operations such that the Partnership’s proportionate share of capital expenses that we would consider maintenance capital under the Golden Lane Participation Agreement is equal to the annual maintenance drilling budget set by our general partner and (ii) cause the wells drilled pursuant to the Golden Lane Participation Agreement to be consistent with the maintenance drilling schedule proposed by our general partner. Our general partner will also have the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.

Omnibus Agreement

We and our general partner are parties to an omnibus agreement with New Source Energy, pursuant to which, among other things, New Source Energy provides management and administrative services for us and our general partner. Through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of such services. 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 we will reimburse our general partner for such payments it makes to New Source Energy.

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We are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit.

New Source Energy is not liable to us for its performance of, or failure to perform, services under this agreement unless there has been a final decision determining that New Source Energy acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful.

The omnibus agreement provides that we must indemnify New Source Energy for any liabilities incurred by New Source Energy attributable to the operating and administrative services provided to us under the agreement, other than liabilities resulting from New Source Energy’s bad faith or willful misconduct. In addition, New Source Energy must indemnify us for any liability we incur as a result of New Source Energy’s bad faith or willful misconduct in providing operating and administrative services under the omnibus agreement. New Source Energy may terminate the omnibus agreement in the event that it ceases to be our affiliate and may also terminate the omnibus agreement if we fail to pay amounts due under that agreement in accordance with its terms. The omnibus agreement may only be assigned by any party with all other parties’ consent.

Contribution, Conveyance and Assumption Agreement

In connection with the closing of our IPO, we and our general partner entered into a contribution, conveyance and assumption agreement with New Source Energy that effects, among other things, portions of the formation transactions, including the transfer of the Partnership Properties to us and the use of the net proceeds of the IPO. All of the transaction expenses incurred in connection with these transactions were paid from proceeds of our IPO. We hold title to the assets and interests acquired through these agreements and also entered into an omnibus agreement with New Source Energy related to these assets and interests as discussed above.

Director Indemnification Arrangements

We and our general partner entered into indemnification agreements with our directors which will generally indemnify our directors to the fullest extent permitted by law. Our general partner maintains director and officer liability insurance for the benefit of its directors and officers.

Transactions with Directors and Officers

New Source Energy engaged Finley & Cook, PLLC to provide various accounting services during the year ended December 31, 2012. Richard Finley, our Chief Financial Officer, was an equity member of Finley & Cook, holding a 31.5% ownership interest. New Source Energy paid Finley & Cook approximately $467,000 in fees for accounting services for the year ended December 31, 2012, of which Mr. Finley’s share based on his ownership interest is approximately $147,000.

Review, Approval or Ratification of Transactions with Related Persons

We have adopted a Code of Business Conduct and Ethics that sets forth our policies for the review, approval and ratification of transactions with related persons. Pursuant to our Code of Business Conduct and Ethics, the directors of our general partner are expected to bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors, or the conflicts committee of our general partner’s board of directors. The executive officers of our general partner are required to avoid conflicts of interest unless approved by the board of directors.

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The board of directors of our general partner has a conflicts committee comprised of one independent director. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with future acquisitions from (or other transactions with) New Source Energy or any of its affiliates. In the case of any sale of equity or debt by us to New Source Energy or any of its affiliates, we anticipate that our practice will be to obtain the approval of the conflicts committee for the transaction. The conflicts committee will be entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee’s approval.

The New Source Group is free to offer properties to us on terms it deems acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by the New Source Group. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production and reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.

We expect that the New Source Group will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed price for any assets it may offer to us in future periods. In addition to these factors, given that New Source Energy is our largest unitholder following the closing of our IPO and through its interest in our incentive distribution rights, it may consider the potential positive impact on its underlying investment in us by offering properties to us at attractive purchase prices. Likewise, it may consider the potential negative impact on its underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.

Director Independence

The board of directors of our general partner has reviewed the independence of our current directors and, based on this review, determined that Mr. Toole is “independent” under the standards of the NYSE and SEC regulations currently in effect. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2012 and 2011, the accounting fees and services (in thousands) charged by BDO USA, LLP, our independent auditors, were as follows:

	Years Ended December 31,
	2012		2011
Audit fees (1)	$	946	$	175
Total accounting fees and services	$	946	$	175

(1)

Audit fees represent fees for professional services rendered in connection with the audit of our annual financial statements, review of our quarterly financial statements and those services normally provided in connection with statutory and regulatory filings including comfort letters, consents and other services related to SEC matters. During the year ended December 31, 2012, fees associated with our IPO totaled $0.6 million.

Audit Committee Pre-Approval Policies and Procedures

The audit committee of our general partner, on at least an annual basis, will review audit and non-audit services performed by BDO USA, LLP as well as the fees charged by BDO USA, LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee pursuant to the audit committee's Pre-approval policies and procedures.

PART IV.

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit Number		Description

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	—	Agreement of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.2 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013).

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Exhibit

Number

Description


3.3	—	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).

3.4	—	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).

3.5	—	Limited Liability Company Agreement of New Source Energy GP, LLC (Incorporated by reference to Exhibit 3.5 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013).

3.6	—	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).

3.7	—	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	—	Credit Agreement, dated as of February 13, 2013, among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent for the lenders party thereto, and the other lender parties thereto (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013).

10.2	—	First Amendment to Credit Agreement, dated as of February 28, 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 March 6, 2013).

10.3	—	Contribution, Conveyance and Assumption Agreement, dated as of February 13, 2013, by and among New Source Energy Corporation, New Source Energy GP, LLC and New Source Energy Partners L.P. (Incorporated by reference to Exhibit 10.7 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013).

10.4	—	Development Agreement, dated as of February 13, 2013, by and among New Source Energy Partners L.P., New Source Energy GP, LLC, New Source Energy Corporation and New Dominion, LLC (Incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013).

10.5†	—	New Source Energy Partners L.P. Long-Term Incentive Plan, dated January 30, 2013 (Incorporated by reference to Exhibit 4.3 of the Partnership’s Registration Statement on Form S-8 (File No. 333-186673) filed on February 13, 2013).

10.6†	—	Form of Restricted Unit Agreement (Subordinated Period Vesting) (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 12, 2013).

10.7†	—	Form of Restricted Unit Agreement (Time-based Vesting) (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 12, 2013).

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Exhibit

Number

Description


10.8	—	Omnibus Agreement, dated February 13, 2013, by and among New Source Energy Corporation, New Source Energy GP, LLC and New Source Energy Partners L.P. (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 13, 2013).

10.9	—	Golden Lane Participation Agreement, dated as of January 10, 2007, among New Dominion, LLC, as operator, Scintilla, LLC and certain other working interest holders in the Golden Lane field party thereto (Incorporated by reference to Exhibit 10.6 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 25, 2013).

10.10	—	First Amendment to Golden Lane Participation Agreement, dated as of October 20, 2007, among New Dominion, as operator, and certain other working interest holders in the Golden Lane field party thereto (Incorporated by reference to Exhibit 10.7 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 25, 2013).

10.11	—	Assignment and Assumption Agreement, dated as of August 12, 2011, between New Source Energy Corporation, as assignee, and Scintilla, LLC, as assignor (Incorporated by reference to Exhibit 10.8 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 25, 2013).

10.12	—	Assignment and Assumption Agreement, dated as of February 13, 2013, between New Source Energy Partners L.P., as assignee, and New Source Energy Corporation, as assignor (Incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 13, 2013).

10.13	—	Form of Director Indemnification Agreement (Incorporated by reference to Exhibit 10.5 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 13, 2013).

10.14	—	Subordinated Promissory Note, dated February 13, 2013, by and among New Source Energy Partners L.P., as borrower and New Source Energy Corporation, as lender (Incorporated by reference to Exhibit 10.6 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 13, 2013).

21.1*	—	List of Subsidiaries of New Source Energy Partners L.P. (Not Applicable)

23.1*	—	Consent of BDO USA LLP

23.2*	—	Consent of Ralph E. Davis Associates, Inc.

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.

99.1*	—	Report of Ralph E. Davis Associates, Inc.

*	Filed herewith.

**	Furnished herewith.

†	Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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 April 1, 2013.

	New Source Energy Partners L.P.

	By:	New Source Energy GP, LLC, its general partner


	/s/ Kristian B. Kos
	By:	Kristian B. Kos
	Title:	Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.

Signature	Title	Date

/s/ David J. Chernicky	Chairman of the Board	April 1, 2013
David J. Chernicky	and Senior Geologist

/s/ Kristian B. Kos	Director, President	April 1, 2013
Kristian B. Kos	and Chief Executive Officer
	(Principal Executive Officer)

/s/ Richard D. Finley	Chief Financial Officer and Treasurer	April 1, 2013
Richard D. Finley	(Principal Financial Officer and
	Principal Accounting Officer)

/s/ Terry L. Toole	Director	April 1, 2013
Terry L. Toole

/s/ V. Bruce Thompson	Director	April 1, 2013
V. Bruce Thompson

/s/ Phil Albert	Director	April 1, 2013
Phil Albert

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. junior Avg

New Source Energy Partners (NSLP) Inactive 10-K2012 FY Annual report

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