New Source Energy Partners 10K 2014 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

(MARK ONE)



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

For the fiscal year ended December 31, 2014



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

For the transition period from ____________ to ____________.

Commission File Number: 001-35809



NEW SOURCE ENERGY PARTNERS L.P.
(Exact name of registrant as specified in its charter)

Delaware	38-3888132
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

914 North Broadway, Suite 230 Oklahoma City, Oklahoma	73102
(Address of principal executive offices)	(Zip Code)

(Registrant’s telephone number, including area code): (405) 272-3028



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 þ

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 þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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 þ 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. o

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 þ Non-accelerated filer o(Do not check if a smaller reporting company) Smaller reporting company o

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

The aggregate market value of our common units held by non-affiliates as of June 30, 2014 was approximately $208.4 million based on the closing price as quoted on the New York Stock Exchange. As of March 6, 2015, the registrant had 16,403,134 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None.

NEW SOURCE ENERGY PARTNERS L.P.

2014 Annual Report on Form 10-K

TABLE OF CONTENTS



		Page

Part I.

Item 1.	Business	11
Item 1A.	Risk Factors	38
Item 1B.	Unresolved Staff Comments	68
Item 2.	Properties	68
Item 3.	Legal Proceedings	68
Item 4.	Mine Safety Disclosures	68

Part II.

Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	69
Item 6.	Selected Financial Data	72
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	74
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	94
Item 8.	Financial Statements and Supplementary Data	97
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	97
Item 9A.	Controls and Procedures	97
Item 9B.	Other Information	99

Part III.

Item 10.	Directors, Executive Officers and Corporate Governance	99
Item 11.	Executive Compensation	104
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	107
Item 13.	Certain Relationships and Related Transactions and Director Independence	109
Item 14.	Principal Accounting Fees and Services	110

Part IV.

Item 15.	Exhibits and Financial Statement Schedules	110

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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 Securities Exchange Commission ("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.

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Glossary of Oil and Natural Gas Terms

The following includes a description of the meanings of certain oil and natural gas industry terms used in this Annual Report on Form 10-K.

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 this report to 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. This ratio reflects an energy content equivalency and not a price or revenue equivalency.

Boe/d: Boe per day.

Btu or British thermal unit: The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of oil, natural gas, or natural gas liquids or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Condensate: A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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, natural gas or natural gas liquids 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.

Developed acreage: The number of acres that are assignable to productive wells or wells capable of production.

Developed oil, natural gas, and natural gas liquids reserves: Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil, natural gas, and natural gas liquids. 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.

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

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

Dry hole or dry well: A well found to be incapable of producing oil, natural gas or natural gas liquids in sufficient quantities to justify completion as an oil, natural gas or natural gas liquids well.

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, natural gas and natural gas liquids producing activities.

Environmental Assessment ("EA"): A study to determine whether a federal action significantly affects the environment, which federal agencies may be required by the National Environmental Policy Act or similar state statutes to undertake prior to the commencement of activities that would constitute federal actions, such as oil, natural gas, and natural gas liquids exploration and production activities on federal lands.

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 a new field or to find a new reservoir in a field previously found to be productive of oil, natural gas or natural gas liquids in another 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. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geological barriers, or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

Gross acres or gross wells: The total acres or wells, as the case may be, in which a working interest is owned.

MBoe: One thousand Boe.

Mcf: One thousand cubic feet of natural gas.

Mcf/d: One Mcf per day.

MMBtu: One million Btu.

Net acres or net wells: The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

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.

NGL: Natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

NYMEX: New York Mercantile Exchange.

Oil: Oil and condensate.

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.

Present value of future net revenues (“PV-10”): The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.

Production costs:

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil, natural gas, and NGLs produced. Examples of production costs (sometimes called lifting costs) are:

a.Costs of labor to operate the wells and related equipment and facilities.

b.Repairs and maintenance.

c.Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

d.Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

e.Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil, natural gas, and NGL producing activities and may also serve transportation, refining and marketing activities. To the extent that the support equipment and facilities are used in oil, natural gas, and NGL producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil, natural gas, and NGLs produced along with production (lifting) costs identified above.

Productive well: A well that is found to be capable of producing oil, natural gas or NGL in sufficient quantities to justify completion as an oil or natural gas well.

Proved developed reserves: Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved reserves: Those quantities of oil, natural gas, and NGL, 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, natural gas, or NGL 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 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 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, natural gas and NGL 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: Estimated remaining quantities of oil, natural gas, NGL 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, natural gas, NGL 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).

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

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 of discounted future net cash flows (“Standardized Measure”): The present value of estimated future cash inflows from proved oil, natural gas, and NGL reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. 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, natural gas, and NGL regardless of whether such acreage contains proved reserves.

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

Working Interest: The interest in an oil or natural gas lease that gives the owner of the interest the right to drill for and produce oil, natural gas, and NGL 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.

Names of Entities and Other Defined Terms

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


•	"general partner" refers to New Source Energy GP, LLC, our general partner;


•	"IPO Properties" refers to the properties, producing wells, and related oil and natural gas interests that were contributed to us by New Source Energy Corporation in connection with our initial public offering;


•	"MCE" or "MCE Entities" refers collectively to MidCentral Energy Partners L.P. (formerly, MCE, LP) and MidCentral Energy GP, LLC (formerly, MCE GP, LLC);


•	"MCLP" refers specifically to MidCentral Energy Partners L.P.;


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


•	"NSEC" refers to New Source Energy Corporation, an independent energy company engaged in the development and production of onshore oil and liquids-rich natural gas projects in the United States;


•	"our management," "our employees," or similar terms refer to the management and personnel of our general partner who perform managerial and administrative services on our behalf;


•	"Partnership," "we," "our," "us," and like terms refer collectively to New Source Energy Partners L.P. and its subsidiaries; and


•	"Scintilla" refers to Scintilla, LLC, the entity from which NSEC acquired substantially all of its assets in August 2011.

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CAUTIONARY STATEMENTS REGARDING FORWARD LOOKING STATEMENTS

This Annual Report on Form 10-K ("Annual Report") of the Partnership includes "forward-looking statements" within the meaning of federal securities laws. These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, the Partnership’s liquidity, capital resources, debt profile, acquisitions and the effects thereof on the Partnership's financial condition, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Partnership’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, and other statements concerning the Partnership’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as "estimate," "assume," "target," "project," "predict," "believe," "expect," "anticipate," "potential," "could," "may," "foresee," "plan," "goal," "should," "intend" or other words that convey the uncertainty of future events or outcomes. All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, potential increases in oil, natural gas, and NGL 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. The Partnership has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Partnership in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Partnership believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Partnership’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Partnership disclaims any obligation to update or revise these forward-looking statements unless required by law, and it cautions readers not to rely on them unduly. While the Partnership’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in "Risk Factors" in Item 1A of Part I of this Annual Report, including the following:


•	business strategies;


•	ability to replace the reserves through acquisitions and the development of our properties;


•	oil, natural gas, and NGL reserves;


•	limited control over non-operated properties;


•	technology;


•	realized oil, natural gas, and NGL prices;


•	impact of commodity prices on the carrying value of our oil and natural gas properties;


•	production volumes;


•	lease operating expenses;


•	general and administrative expenses;


•	future operating results;


•	cash flow and liquidity;


•	availability of production equipment;


•	availability of oil field labor;


•	capital expenditures;


•	availability and terms of capital;


•	ability to repay current indebtedness and make distributions;


•	limitations on operations resulting from debt restrictions and financial covenants;


•	marketing of oil, natural gas, and NGL;


•	ability to identify, complete and integrate acquisitions of assets or businesses;


•	the volatility of realized oil and natural gas prices;

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•	the availability or cost of equipment, raw materials, supplies or personnel;


•	the availability of transportation facilities;


•	general economic conditions;


•	competition in the oil and natural gas and oilfield services industries;


•	effectiveness of risk management activities;


•	environmental conditions and liabilities;


•	customer concentration;


•	geographical concentration of our operations;


•	governmental regulation and taxation;


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


•	developments in oil and natural gas producing countries; and


•	plans, objectives, expectations and intentions.

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PART I.



ITEM 1.	BUSINESS

GENERAL

We are a Delaware limited partnership formed in October 2012 to own and acquire oil and natural gas properties in the United States. We are engaged in the development and production of onshore oil and natural gas properties that extend across conventional resource reservoirs in east-central Oklahoma. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation. In addition, we are engaged in oilfield services through our oilfield services subsidiaries. Our oilfield services business provides essential wellsite services during the drilling and completion stages of a well, including full service blowout prevention installation, pressure testing services, including certain ancillary equipment necessary to perform such services, well testing and flowback services to companies in the oil and natural gas industry primarily in Oklahoma, Texas, New Mexico, Kansas, Pennsylvania, Ohio and West Virginia.

Available Information

Our principal executive offices are located at 914 North Broadway, Suite 230, Oklahoma City, Oklahoma 73102, and our telephone number is (405) 272-3028. Our website is located at www.newsource.com. We make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (“SEC”), free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Any materials that we have filed with the SEC may be read and copied at the SEC's Public Reference Room at 100 F Street, N.E., Room 1580, Washington D.C. 20549 or accessed via the SEC's website at www.sec.gov. Information on the operation of the SEC's Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330.

BUSINESS STRATEGIES

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. To achieve our objective, we intend to execute the following business strategies:


•	Focus on Cost Efficiency and Capital Allocation. By leveraging our experienced workforce and scalable operational structure, we are able to achieve cost efficiencies and sustainable returns in the areas we provide oilfield services.

•

Provide High-Value and Essential Services to Our Customers. We provide essential wellsite services that are necessary for the safe drilling, completion and lifetime performance of a well. Many of our customers include larger producers who generally have stringent quality control, health, safety and environmental standards due to the potential for high financial and reputational risks associated with a well failure. Given that our services generally represent only a small portion of the total cost of drilling and completing a well, we market to and serve customers who are focused on quality and safety at competitive prices.


•	Reduce Exposure to Commodity Price Risk. We enter into derivative contracts to mitigate commodity price volatility inherent in the oil and natural gas industry. Our hedging strategy includes entering into commodity derivative contracts for a portion of our estimated total production over a three to five-year period at any given point in time.


•	Organic Expansion. Based on the knowledge and experience of our oilfield services’ management team and the customer base developed at our oilfield services subsidiaries, we believe we can grow our oilfield services business organically by expanding into new geographic regions and developing new service lines in areas where we believe we have the expertise to gain market share.


•	Pursue Accretive Acquisitions. We seek to make accretive acquisitions of oil and natural gas properties and oilfield services companies that complement our existing operations. We focus on acquisition opportunities that enable us to utilize a strategic or technical advantage based on our existing liquidity, operational experience and access to infrastructure.

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DEVELOPMENTS

Recent Developments

In the fourth quarter of 2014 and continuing in 2015, oil and natural gas prices have declined significantly, which has caused a reduction in revenue from our oil, natural gas and NGL production at the end of 2014 and is expected to continue in 2015. Additionally, lower oil and natural gas prices impact the amount of oil, natural gas and NGL that we can produce economically.

Lower oil and natural gas prices have also resulted in a reduction in demand for our oilfield services. If oil and natural gas prices remain volatile, or if oil and natural gas prices remain low or decline further from recent levels, the spending patterns of our customers may continue to be impacted, resulting in the drilling of fewer new wells or lower production spending on existing wells. Unfavorable oil and natural gas prices may render many of our customers’ development and production projects uneconomic and may result in a material reduction in demand for our services.

Refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this report for additional discussion.

2014 Developments

Acquisitions

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

In June 2014, the Partnership acquired 100% of the outstanding membership interests in Erick Flowback Services LLC ("EFS") and 100% of the outstanding membership interests in Rod's Production Services, L.L.C. ("RPS") for total consideration of approximately $113.2 million (the "Services Acquisition"). EFS and RPS, which are affiliates of each other, are oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry.

Equity Offerings

In April 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million. We used $5.0 million of the net proceeds from the offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes.

In October 2014, the Partnership and our general partner entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (the “Sales Agent”). Pursuant to the terms of the EDA, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. Sales of such common units, if any, will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange ("NYSE") at market prices or as otherwise agreed by the Partnership and the Sales Agent. On October 6, 2014, the Partnership sold 720,000 common units under the EDA for proceeds of approximately $16.2 million, net of offering costs, which included a commission to the Sales Agent of 1.75% on the principal amount of the offering. Proceeds were used to pay down a portion of the Partnership's outstanding debt and for general corporate purposes. No additional sales were made through December 31, 2014.

Debt

In November 2014, the borrowing base on our senior secured revolving credit facility (the "credit facility") was reduced from $102.5 million to $90.0 million as a result of our semi-annual redetermination. The borrowing base is dependent on our estimated oil, natural gas, and NGL reserves, which have declined as a result of lower oil, natural gas, and NGL prices.

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BUSINESS SEGMENTS AND OPERATIONS

We currently operate in two reportable operating segments: (i) our exploration and production segment; and (ii) our oilfield services segment. In line with the growth of our business, we routinely evaluate our reportable operating segments and we believe that these two segments are appropriate and consistent with how we manage our business and analyze our results of operations. Our operating segments are described in more detail below. Financial information regarding each segment is provided in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and "Note 16 - Business Segment Information" to the Partnership’s consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.

Exploration and Production

Our exploration and production segment focuses on production of the Partnership’s oil and natural gas properties, which consists of non-operated working interests, primarily in the Misener-Hunton formation, or Hunton formation, a conventional resource reservoir located in east-central Oklahoma, primarily in Pottawatomie, Seminole and Okfuskee Counties. The Hunton formation is a liquids-rich subterranean limestone reservoir stretching across Oklahoma. The formation has over 700 horizontal wells and an average of 60 wells drilled per year over the last eight years. 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 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. See "- Our Conventional Resource Plays" below for additional discussion of the Hunton formation.

As of December 31, 2014, we had proved reserves of approximately 16.3 MMBoe, of which approximately 83.0% were proved developed reserves. Of those proved developed reserves, 11.2% were comprised of oil, 31.9% of natural gas and 56.9% of NGL. As of December 31, 2014, we had 145,919 gross (60,019 net) acres, of which 18,899 gross (5,270 net) acres were undeveloped. As of December 31, 2014, we had 83 gross (16.2 net) proved undeveloped drilling locations, of which 19 gross (6.8 net) were infill drilling locations. During the year ended December 31, 2014, our average net daily production was approximately 4,550 Boe/d. As a result of current oil and natural gas prices, we are not currently drilling on our properties. Our drilling plan for 2015 is dependent on commodity prices; however, we do not currently anticipate drilling any new wells until the second half of 2015. During 2014, we completed 26 gross (7.4 net) wells.

The following table summarizes information related to our estimated oil, natural gas, and NGL reserves as of December 31, 2014 and the average net production for the year ended December 31, 2014 from our properties. Reserves were estimated using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months.



	Estimated Proved Reserves as of December 31, 2014									Production for the Year Ended December 31, 2014
	Total Proved (MBoe)	Oil		Natural Gas		NGL		PV-10 ($ in MM) (1)		Average Net Daily Production (Boe/d)	Average Working Interest
Proved reserves	16,317.2	10.1	%	33.2	%	56.7	%	$	179.3	4,550	41.9	%

_______________

(1)

PV-10 typically differs from the Standardized Measure because it does not include the effects of income tax. We are 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 are equivalent. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our oil and natural gas 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.

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Properties

Our properties are conventional resource plays located in the Golden Lane, Luther, and Southern Dome fields in east-central Oklahoma. These fields produce from the Hunton and Arbuckle formations, consist of mature, legacy oil, natural gas, and NGL reservoirs and comprise non-operated working interests in producing and undeveloped leasehold acreage.

Our Conventional Resource Plays

The type of conventional resource play on which we currently 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%. 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

Our contract operator'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 currently focus.

Our contract operator 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, NGL, 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/d, 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 NGL 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. Our contract operator historically has been successful with infill drilling based

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on its evaluation of appropriate wellbore placement in order to create the best flow rates for reservoir drainage. In conjunction with our contract operator and other working interest partners, we 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. Our drilling plans are dependent on commodity prices. In a low commodity price and rising operating costs environment, our drilling plan would be curtailed. Our drilling plan for 2015 is dependent on commodity prices; however, we do not currently anticipate drilling any new wells until the second half of 2015.

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, natural gas, and NGL 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, natural gas, and NGL 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 our contract operator, 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.

Our contract operator's experience has been that very few other interest owners elect to participate in the drilling of new wells in our area of operations. Our contract operator and its affiliates have drilled a total of 70 wells over the three years ended December 31, 2014 in the areas of mutual interest defined by the Golden Lane Participation Agreement through successful forced pooling efforts. For a description of the Golden Lane Participation Agreement, see “Certain Agreements Governing Our Exploration and Production Operations-Golden Lane Participation Agreement” below. 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.

Specialized Processes

We, through our contract operator, 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 our contract operator, using the latest available drilling, completion, and production technology to create natural conductive flow paths that enable access to the hydrocarbons within. 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, natural gas and oil from source rock formations in a way that enables those formations to produce oil and liquids-rich natural gas. 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.

Unlike typical oil, natural gas, and NGL reservoirs, which show declining oil, natural gas, and NGL production rates with time, this type of reservoir typically increases its oil, natural gas, and NGL production rate over an initial period of approximately 6 months, holds flat for a period of approximately 12 months, and then, as the reservoir is depressurized, the wells assume a more typical decline curve.

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Proved Reserves

Preparation of Reserve Estimates

Uncertainties are inherent in estimating quantities of proved reserves, including many factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil, natural gas, and NGL that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices or development costs and production expenses, may require revision of such estimates. Accordingly, oil, natural gas, and NGL quantities ultimately recovered will vary from reserve estimates. See “Risk Factors” in Item 1A of Part I of this report for a description of some of the risks and uncertainties associated with our business and reserves.

Independent Reserve Engineers. Estimates of our proved reserves were prepared by Ralph E. Davis Associates, Inc. ("RED"), our independent reserve engineer. RED, which was founded in 1924, performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1529. Within RED, the technical person primarily responsible for preparing the estimates shown in this report was its president, Allen C. Barron. Mr. Barron has been practicing consulting petroleum engineering at RED 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.

The process performed by RED to prepare reserve amounts included their estimation of reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. RED also prepared estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a)(22) and subsequent SEC staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, RED did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil, natural gas, and NGL production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention which brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto.

See Exhibit 99.1 to this report for the estimates of proved reserves provided by RED.

Internal Controls over Reserves Estimation Process. Our senior engineer works closely with RED to ensure the integrity, accuracy and timeliness of data that is furnished to it for its reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide RED other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their evaluation of our reserves.

We maintain internal evaluations of our reserves in a secure reserve engineering database. RED interacts with our senior engineer and our contract operator’s internal petroleum engineers and geoscience professionals to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by our senior management on a semi-annual basis and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our revolving credit facility. Our reserve estimates are evaluated by RED at least annually.

The technical person, employed by our general partner, primarily responsible for both overseeing preparation of our reserves estimates and the third-party reserve audit of our reserves is Carol Bryant, Senior Engineer of our general partner. 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. Ms. Bryant consults with RED during the reserve estimation process to review properties, assumptions and relevant data.

Technology Used to Establish Proved Reserves. Under SEC rules, proved reserves are those quantities of oil, natural gas, and NGL, 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

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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 reserves 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, natural gas, and NGL in place in certain areas.

Reserve Quantities

The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2014, 2013 and 2012, all of which were prepared by independent petroleum engineers. The PV-10 values shown in the table below are not intended to represent the current market value of our estimated proved reserves as of the dates shown. The reserve reports were based on our contract operator's drilling schedule and the average price during the 12-month periods ended December 31, 2014, 2013 and 2012, using first-day-of-the-month prices for each month. We estimate that approximately 32.2% of our current proved undeveloped reserves will be developed by the end of 2016 and all of our current proved undeveloped reserves will be developed by the end of 2019. See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.



	Estimated Proved Reserves as of December 31, 2014 (1)									Production for the Year Ended December 31, 2014			Number of Wells/Drilling Locations as of December 31, 2014
Proved Reserves	Total Proved (MBoe)	Percent of Total	Oil		Natural Gas		NGL		PV-10 ($ in MM) (2)	Average Net Daily Production (Boe/d)	Average Working Interest		Gross	Net
Producing	13,540.2	83.0	11.2	%	31.9	%	56.9	%	171.4	4,550	47.9	%	313	150.1
Undeveloped	2,777.0	17.0	4.8	%	39.6	%	55.6	%	7.9	—	19.5	%	83	16.2
Total	16,317.2	100.0	10.1	%	33.2	%	56.7	%	179.3	4,550	41.9	%	396	166.3

_______________

(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. The prices used in our reserve reports are based on index prices, which were $94.99 per Bbl of oil, $4.35 per Mcf of natural gas and $36.09 per Bbl of NGL, as adjusted for differentials. Adjustments were made for location and the grade of the underlying resource, which resulted in an average decrease to the index price of $3.01 per Bbl of oil, $0.22 per Mcf of natural gas and $1.14 per Bbl of NGL.

(2)

Proved Developed Reserves. As of December 31, 2014, 2013 and 2012, our proved developed reserves were 13.5 MMBoe, 12.5 MMBoe and 8.4 MMBoe, respectively. An acquisition in 2014 and multiple acquisitions in 2013 resulted in increases to our proved developed reserves, partially offset by production.

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Proved Undeveloped Reserves. As of December 31, 2014, 2013 and 2012, our proved undeveloped reserves were 2.8 MMBoe, 8.2 MMBoe and 5.8 MMBoe, respectively. All proved undeveloped locations are scheduled to be spud within five years of the day first booked as proved undeveloped reserves and target the Hunton Formation. 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. Pursuant to the development agreement, our general partner has 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 “- Forced Pooling Process.”

The following table presents changes applicable to the proved undeveloped reserves on our properties during the years ended December 31, 2013 and 2014 (in MBoe):



Balance, December 31, 2012	5,827
Revisions	(256	)
Purchases of reserves	1,031
Extensions and discoveries	2,122
Conversion to proved developed reserves	(569	)
Balance, December 31, 2013	8,155
Revisions	(5,751	)
Purchases of reserves	—
Extensions and discoveries	889
Conversion to proved developed reserves	(516	)
Balance, December 31, 2014	2,777

During the year ended December 31, 2013, we drilled a total of 28 gross (10.6 net) development wells for a total aggregate net capital cost of approximately $10.6 million. We developed 569 MBoe (10%) of the proved undeveloped reserves attributable to our properties through the drilling of 6 gross (2.2 net) development wells at an aggregate net capital cost of approximately $2.6 million. In addition, we drilled 22 gross (8.4 net) development wells on acreage that was acquired in 2013 at an aggregate net capital cost of approximately $8.0 million.

During the year ended December 31, 2014, we developed 516 MBoe of the proved undeveloped reserves attributable to our properties through the drilling of 16 gross (4.1 net) development wells at an aggregate net capital cost of approximately $9.6 million. Revisions for the year ended December 31, 2014 are primarily attributable to the reclassification of certain proved undeveloped reserves to probable reserves because our expected drilling plan has been curtailed as a result of low commodity prices and rising costs to drill wells.

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Significant Fields

Oil, natural gas and NGL production for fields containing more than 15% of our total proved reserves at each year end are presented in the table below. The Golden Lane and Southern Dome fields each contained more than 15% of our total proved reserves at December 31, 2014, 2013 or 2012.



Year Ended December 31,	Oil (MBbls)	Natural Gas (MMcf)	NGL (MBbls)	Total
2014
Golden Lane	628	23,888	8,506	13,115.3
Southern Dome	1,006	7,521	354	2,613.5
2013
Golden Lane	899	31,449	12,467	18,607.5
Southern Dome	521	3,377	156	1,239.8
2012
Golden Lane	529	24,135	9,704	14,255.5

Golden Lane Field. The Golden Lane Field is located in east-central Oklahoma and produces from the Hunton Formation, a liquids-rich subterranean limestone reservoir. The field includes the initial six townships of our IPO Properties and incorporates the adjacent townships to the north and east. Our properties in the Golden Lane field are developed and producing under three separate participation agreements: the Golden Lane Participation Agreement, the Paden Participation Agreement and the Eight East Participation Agreement.

Southern Dome Field. The Southern Dome Field is located within the Oklahoma City limits in Oklahoma County and is part of the historic Oklahoma City field discovered in 1928. The field is located on the south end of the Nemaha ridge and production is from the Arbuckle reservoir at an average depth of 6,500 feet.

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Production and Price History

The following table summarizes information related to our production of our oil, natural gas and NGL products as of December 31, 2014, 2013 and 2012.



	Year Ended December 31,
	2014		2013		2012
Production Data
Oil (Bbls)	163,338		84,273		61,010
Natural gas (Mcf)	3,673,836		2,764,336		2,278,342
NGL (Bbls)	885,117		790,234		711,195
Total production (Boe)	1,660,761		1,335,230		1,151,929
Average daily production (Boe/d)	4,550		3,658		3,156

Average Prices
Oil (per Bbl)	$	91.26	$	96.00	$	91.30
Natural gas (per Mcf)	$	4.23	$	3.62	$	2.65
NGL (per Bbl)	$	35.08	$	36.50	$	33.74
Total (per Boe)	$	37.02	$	35.15	$	30.90

Expenses per Boe
Production costs (1)	$	11.21	$	9.46	$	5.40
Production taxes	$	1.71	$	2.00	$	0.99

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(1) Includes lease operating expense and workover expense.

Production costs have increased primarily as a result of acquired oil and natural gas properties in the Luther and Southern Dome participation areas. The Southern Dome participation area produces significantly more oil than the other participation areas, and the production of oil typically has higher lease operating expenses. Additionally, costs for water disposal are higher due to the increased use of water in production from the Southern Dome field.

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

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest, and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2014.



	Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Total	55	33.6	258	116.5	313	150.1

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The following table sets forth the number of producing horizontal and vertical completions in which we own a working interest as of December 31, 2014.



	Horizontal		Vertical		Total
	Gross	Net	Gross	Net	Gross	Net
Total	251	109.8	62	40.3	313	150.1

Acreage

The following table sets forth information as of December 31, 2014 related to our developed and undeveloped leasehold acreage as of December 31, 2014.

Developed

Undeveloped

Total

Gross

Net

Gross

Net

Gross

Net

Total

127,020

54,749

18,899

5,270

145,919

60,019

The majority of our undeveloped acreage is subject to material near-term lease expiration risk. As of December 31, 2014, we held approximately 5,270 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, 2017, of which 3,105 net acres are scheduled to expire between January 1, 2015 and December 31, 2015, 1,358 net acres are scheduled to expire between January 1, 2016 and December 31, 2016, and 807 net acres are scheduled to expire between January 1, 2017 and December 31, 2017. Of our total estimated proved undeveloped reserves as of December 31, 2014 of 2,777 MBoe, 608 MBoe, or approximately 21.9%, is attributable to 27 gross (3.0 net) drilling locations within undeveloped acreage covered by leases set to expire before the associated wells are scheduled to be drilled. Our 2015 drilling plan is dependent on commodity prices. We intend, in the ordinary course of business, to regularly evaluate the lease expirations and drilling schedule, to maximize our undeveloped acreage position while considering the economic viability of drilling at the current market price environment. 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. See “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.”

Drilling Activities

The following table sets forth information with respect to wells drilled and completed by us, our predecessor, or the previous owners during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. At December 31, 2014, there were no wells pending completion or with drilling in progress. Drilling has been suspended at this time due to low commodity prices. Our drilling plan for 2015 is dependent on commodity prices; however, we do not currently anticipate drilling any new wells until the second half of 2015.

The following table describes the development wells drilled on our acreage during the years ended December 31, 2014, 2013 and 2012.



	Productive Wells		Dry Wells		Total
Year	Gross	Net	Gross	Net	Gross	Net
2014	26	7.4	—	—	26	7.4
2013	28	10.6	—	—	28	10.6
2012	12	3.8	—	—	12	3.8

No exploratory wells were drilled on our acreage during these three years.

Delivery Commitments

We have no commitments to deliver a fixed and determinable quantity of our oil or natural gas production in the near future under our existing contracts.

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Title to Properties

Prior to completing an acquisition of producing oil and natural gas properties, we perform title reviews, or obtain indemnification with respect to title, on significant leases, and depending on the materiality of properties, we may obtain a title opinion or review previously obtained title opinions. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the titles to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our own expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property.

We believe that we have satisfactory title to all of our material assets. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens or encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this report.

Derivative Activities

Our hedging strategy includes entering into commodity derivative contracts for a portion of our estimated total production over a three- to five-year period at any given point in time. 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 or collar contracts. By reducing 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. For a description of our commodity derivative contracts, see “Quantitative and Qualitative Disclosures about Market Risk” in Part II, Item 7A of this report.

Marketing and Customers

The majority of our revenue has historically been generated by our exploration and production segment. Our principal products are oil, natural gas and NGL, which are marketed and sold primarily to purchasers that have access to nearby pipeline facilities, refineries or other markets. Typically, oil is sold at the wellhead at field-posted prices, and natural gas and NGL 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.

Our contract operator 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 oil, natural gas and NGL 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 oil produced at our properties.

Oil Sales/Customers: The 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, 2014, sales to UPP comprised 24.3% of our total oil, natural gas and NGL sales for the year ended December 31, 2014.

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Natural Gas and Natural Gas Liquids Sales/Customers: Our contract operator has previously dedicated all natural gas and NGL produced and sold from wells it operates in the Golden Lane and Southern Dome participation areas to Scissortail Energy, LLC ("Scissortail"), a subsidiary of Kinder Morgan Energy Partners LP, pursuant to a long-term gas sales contract entered into on May 1, 2005, between an affiliate of our 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. Sales to Scissortail comprised 71.2% of our total oil, natural gas and NGL sales for the year ended December 31, 2014.

Oilfield Services

Our oilfield services segment was established with the acquisition of MCE in November 2013 (the "MCE Acquisition"), as further described in "Note 2 - Acquisitions" to the consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report. Additionally, in June 2014, we acquired oilfield service companies that specialize in providing well testing and flowback services. We operate an oilfield services business headquartered in Oklahoma City, Oklahoma, and provide services to companies engaged in the production of oil, natural gas, and NGL from United States onshore unconventional reservoirs. We provide essential wellsite services during the drilling and completion stages of a well, including blowout prevention, surface valve and flowback services for both horizontal wells and vertical wells. We offer our services in several oil, natural gas, and NGL production regions in North America, including the Mid-Continent region (Oklahoma, Kansas and the Texas Panhandle), the Permian Basin region (Texas and New Mexico), the Eagle Ford shale region in South Texas, and the Marcellus and Utica shale regions (Pennsylvania, Ohio and West Virginia).

Blowout Prevention Services

Our blowout prevention services consist primarily of installing and pressure testing blowout preventors ("BOP") during the drilling and completion stages of a well. A BOP is a large, specialized valve, typically installed in stacks, used to seal, control and monitor oil, natural gas, and NGL wells. BOPs were developed to control extreme pressures and uncontrolled flow of oil, natural gas and any other production fluids emanating from a well reservoir during drilling, which can lead to well failures known as blowouts. In addition to controlling the downhole pressure and the flow of oil, natural gas, and NGL, BOPs are intended to prevent drill pipe, casing, tools and drilling fluid from being blown out of the wellbore. Proper installation and pressure testing of BOPs is critical to the safety of the crew, rig and environment.

Surface Valve Services

Our surface valve services consist of assembling, installing and pressure testing surface valves, such as fracturing valves and wellhead valves, during the drilling and completion stages of a well. The primary purpose of a wellhead valve is to provide the suspension point and pressure seals for the casing strings that extend from the bottom of the wellbore sections to the surface pressure control equipment. The frac valve assemblies help to facilitate the hydraulic fracturing process. These valves provide the structural and pressure-containing interface for the drilling, completion and production equipment. To verify valve seals and integrity, we pressure test both (i) wellhead valves, which are installed and pressure tested during the drilling phase of the well and (ii) fracturing valves, which are installed and pressure tested during the completion phase of the well.

Flowback Services

Our flowback services consist of production testing, solids control, hydrostatic testing and torque services during the initial completion and production phases of the well. Flowback is fluid that returns to the surface with produced oil, natural gas, and NGL at the completion of hydraulic fracturing. It is a mixture of frac fluids and proppant as well as clay, salts, rock particles and other naturally occurring elements. After the hydraulic fracturing of a well is completed, our specialists, including flow hands and well testers, help to stabilize the well and bring it online by performing production testing, solids control, hydrostatic testing and monitoring of the wellbore. Flowback services also include separating water, sand, proppant and plugs from the initial production stream. Our well testing services provide necessary data to operators, including well pressure readings, the mix of oil, natural gas, and NGL, formation pressures and other metrics, that assist the operator in characterizing the well and reservoir and optimizing the plan of production.

Marketing and Sales

Our ability to grow our oilfield services business depends on our ability to evaluate and select highly-qualified personnel, acquire and maintain suitable equipment, organically expand into servicing new and existing plays, and acquire and integrate additional oilfield services companies in a highly-competitive environment. Additionally, our oilfield services segment specializes in increasing efficiencies and safety in drilling and completion processes, such as the installation and pressure testing of blowout

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preventers. The functions of the blowout preventer are to maintain pressure through the wellbore, confine fluid to the wellbore, allow controlled volumes of fluid to be added to the wellbore, center and hang strings of drill pipe in the wellbore, and to ultimately “kill” a well should the need arise. Our oilfield services segment has established operations in multiple regions across the United States as a means to lessen exposure to localized volatility in drilling activity by having a footprint in various geographic basins.

Demand for domestic onshore oilfield services is a function of the willingness of exploration and production companies to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the United States Though not the only determinant, oil, natural gas, and NGL prices are often key variables in an exploration and production company’s decision to deploy capital for the drilling and development of its resource base. When oil or natural gas prices increase, exploration and production companies generally increase their capital expenditures, resulting in greater revenues and profits for oilfield service companies. Likewise, significant decreases in the prices of those commodities typically lead exploration and production companies to reduce their capital expenditures, which lowers the demand for oilfield services. Due to the decline in oil and natural gas prices noted in the fourth quarter of 2014 and continuing into 2015, our oilfield services customers have decreased their drilling activity and planned capital expenditures, which is expected to result in lower revenue for our oilfield services segment.

Over the past decade, exploration and production companies have focused on many of North America’s unconventional resource plays, including those in which we operate, through the application of new horizontal drilling and completion technologies. The successful and economic production of unconventional resource plays typically requires horizontal drilling, fracking and stimulation services. Drilling-related activity for unconventional resources requires that more wells are drilled relative to conventional resources. In addition to the number of horizontal wells drilled in the United States, the number of wells drilled per rig, the length of well laterals, the total footage drilled and the number of frac stages have continued to increase, creating an increased demand for drilling- and completion-related services.

Horizontal wells drilled in unconventional formations tend to involve a higher degree of drilling and completion service intensity than conventional wells. These unconventional reservoirs can be higher pressure reservoirs, increasing the demand for services, such as ours, that focus on the integrity of the pressure control equipment with the goal of avoiding environmental or operational circumstances that could otherwise negatively impact the drilling process. These services are often more complex, requiring new technologies, completion techniques and equipment designed to increase recovery rates, lower production costs and accelerate field development. Despite the proliferation of unconventional resource development and associated oilfield services, the market for BOP-related services, pressure testing, well testing and flowback services remains relatively fragmented in the onshore United States market.

Our facilities include leased executive headquarters and leased field headquarters in Oklahoma City, OK as well as eight leased field offices in Oklahoma, five leased field offices in Texas (three in the Eagle Ford shale region and two in the Permian Basin region), and one leased field office in each of New Mexico, Pennsylvania and Ohio.

Oilfield Services Customers. The addition of our oilfield services segment in November 2013 and acquisition of three oilfield service companies in June 2014 expanded our customer base. For the year ended December 31, 2014, two customers individually accounted for more than 10% of our total oilfield services revenue. See "Note 16 "Business Segment Information" to the Partnership’s consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.

COMPETITION

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil, natural gas, and NGL and securing equipment and trained personnel. As a relatively small company, many of our competitors are major and large independent oil and natural gas companies or diversified oilfield services companies that possess and employ financial, technical and personnel resources substantially greater than our resources. The larger exploration and production 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. Additionally, larger oilfield services companies may be able to offer potential customers a broader range of services, products and technical expertise. 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, and our ability to grow our oilfield services business will depend on our ability to evaluate and select suitable people and equipment, organically expand into servicing new and existing plays and our success in acquiring and integrating additional oilfield services companies in a highly competitive environment.

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CERTAIN AGREEMENTS GOVERNING OUR EXPLORATION AND PRODUCTION OPERATIONS

Development Agreement with New Dominion and NSEC

We are party to a development agreement with our contract operator and some of its affiliates with respect to the drilling of our proved undeveloped reserves that comprise a portion of our properties. During each of our fiscal years ending December 31, 2013 through December 31, 2016, we have agreed to maintain an annual maintenance drilling budget averaging no less than $8.2 million to drill certain of our proved undeveloped locations and maintain our producing wells. Based on amounts incurred in 2013 and 2014, we have fulfilled our commitment for the maintenance drilling budget under the Development Agreement. 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, see “- Golden Lane Participation Agreement” below.

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.

Golden Lane Participation Agreement

The Golden Lane Participation Agreement controls the development and operation of the Golden Lane field and provides New Dominion, as contract 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 above. 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 contract 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% less any existing royalties or overriding royalty interests that burden the applicable lease; however, if existing royalties and overriding royalty interests exceed 20% 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.

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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 thirty days of a new well notice from the contract operator or at least five days prior to the spud date for the new well, depending on which event occurs later, unless a majority of the working interest partners vote to go non-consent.

In return for serving as the contract 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 thirty days of the date of New Dominion’s invoice.

Paden Project Participation Agreement

In March 2014, the Partnership, New Dominion, as contract operator, and unaffiliated third parties that also own working interests in the Eight East area of mutual interest entered into a participation agreement (the "Paden Project Participation Agreement").

The Paden Project Participation Agreement controls the development and operation of our properties in Townships 12 and 13 North, Range 5, 6 and 7 East, which is part of the greater Golden Lane field, and provides New Dominion, as contract operator, with authority to control the development and operation of these properties. New Dominion also is empowered to acquire additional leasehold within the Paden Project area of mutual interest after approval on a bi-annual basis of a budget for leasehold acquisition costs. This leasehold is assigned to the working interest owners on a bi-annual basis, and the working interest owners are obligated to reimburse New Dominion monthly for their proportionate share of the costs of such additional leasehold, plus an allocated percentage of the costs of New Dominion’s land personnel engaged in activities relating to the Paden Project area of mutual interest. The Paden Project Participation Agreement permits New Dominion to hold record title to any undeveloped leasehold within the area of mutual interest that it acquires pending these bi-annual assignments. Although New Dominion would hold record title to any such undeveloped leasehold, the Paden Project Participation Agreement requires the assignment to us of the leasehold bi-annually or upon the earlier commencement of development, and it is this right on which we rely in connection with estimating any proved undeveloped reserves associated with such acreage in our reserve reports. Each party to the Paden Project Participation Agreement has the option, but not the obligation, to participate in future wells proposed by the contract operator for its proportionate share of the costs associated with such wells. The parties also have agreed to pay New Dominion their proportionate share of a $35,000 development fee for each well in which they participate upon spud of the well. In addition, the parties also have agreed to pay New Dominion their proportionate shares of an initial connection charge of $300,000 per well in the Paden Project area, subject to increase in certain circumstances, for connection and access to its saltwater disposal infrastructure within the Paden Project area and also to pay New Dominion their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells. While New Dominion remains the sole owner of the saltwater disposal infrastructure servicing the Paden Project area, the participants have a priority right of access to this disposal infrastructure.

In the event that New Dominion acquires additional leasehold acreage for the benefit of the parties to the Paden Project Participation Agreement (including by means of forced pooling), New Dominion will assign record title to the other parties to the Paden Project 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 19.75% less any existing royalties or overriding royalty interests that burden the applicable lease; however, if existing royalties and overriding royalty interests exceed 18.75% 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 Paden Project 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

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within any assignment pursuant to the Paden Project Participation Agreement shall be limited to only those depths and formations so acquired by New Dominion.

The Paden Project 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 in which we elect to participate. If we decline to participate in a new well that New Dominion proposes, we will not be eligible to participate in any other wells drilled in the same section, 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 development costs. The Paden Project Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs for wells in which we elect to participate within 30 days of a new well notice from the contract operator at least five days prior to the spud date for the new well, depending on which event occurs earlier.

In return for serving as the contract operator of the Paden Project area, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Paden Project 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.

Luther Joint Operating Agreement

In connection with our acquisition of certain oil and natural gas properties from NSEC and Scintilla in March 2013, we succeeded to those parties’ rights and obligations under a joint operating agreement governing the Luther participation area, which we refer to as the “Luther JOA.” New Dominion is the contract operator of the Luther field pursuant to the Luther JOA, and there are no other working interest owners party to this agreement.

Under the Luther JOA, New Dominion will hold record title to undeveloped leasehold within the Luther area of mutual interest for our benefit pending development of the applicable leasehold. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold plus a fee of 15% until development has commenced. Although the operator holds record title to this undeveloped leasehold, the Luther JOA requires the assignment to us of leasehold after it is developed, and it is this right on which we rely in connection with estimating any proved undeveloped reserves associated with such acreage in our reserve reports. New Dominion is permitted to acquire additional leasehold within the Luther field for our account, and in such a circumstance we are required to pay New Dominion for our proportionate share of the actual cost of such acreage plus a fee of 15%. We also are required to advance up to $1 million in acreage acquisition costs from time to time for future acquisitions within the Luther field as often as every six months if requested by the contract operator. The Luther JOA also contains provisions governing the connection and access to New Dominion’s saltwater disposal infrastructure that are similar to those found in the Golden Lane Participation Agreement, except that the current connection fee is $400,000 per well for the Luther field as compared to $300,000 per well for the Golden Lane field. Additionally, the Luther JOA requires us to pay New Dominion for our proportionate share of the cost of other infrastructure deemed necessary by New Dominion to economically produce oil, natural gas, and NGL, plus a fee of 15% of such amounts.

In the event that New Dominion acquires additional leasehold acreage for our benefit in the Luther area of mutual interest (including by means of forced pooling), New Dominion will assign record title to us in our proportionate share. In connection with any such assignment, New Dominion will retain an overriding royalty interest in an amount equal to 21% less any existing royalties or overriding royalty interests that burden the applicable lease; however, if existing royalties and overriding royalty interests exceed 21% 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 Luther JOA. 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 Luther JOA shall be limited to only those depths and formations so acquired by New Dominion.

The Luther JOA 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, and it 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 we decline to participate in a new well that New Dominion proposes, we will not be eligible to participate in the next nine wells in adjacent drilling and spacing units to such 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 development costs. In addition, if we decline to participate in a new well that New

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Dominion proposes, we will relinquish our interest in the new well and our share of production from the new well until such time as 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 typically must pay our share of drilling and completion expenses no more than 30 days following notice from the contract operator, and in some circumstances the operator may require us to advance these amounts in the month before the operator expects to incur them.

In return for serving as the contract operator of the Luther participation area, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Luther JOA, 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 the contract operator’s invoice.

Eight East Participation Agreement

In connection with the acquisitions of oil and natural gas properties from NSEC in May 2013 and from Scintilla in July 2013, we succeeded to those parties’ rights and obligations under the Eight East Participation Agreement. The other parties to the Eight East Participation Agreement include New Dominion, as contract operator, and unaffiliated third parties that also own working interests in the Eight East area of mutual interest.

The Eight East Participation Agreement controls the development and operation of our properties in Townships 10 and 11N, Range 8E, which is part of the Greater Golden Lane field, and provides New Dominion, as contract operator, with authority to control the development and operation of these properties. New Dominion also is empowered to acquire additional leasehold within the Eight East area of mutual interest after approval on a quarterly basis of a budget for leasehold acquisition costs. This leasehold is assigned to the working interest owners on a quarterly basis, and the working interest owners are obligated to reimburse New Dominion quarterly for their proportionate share of the costs of such additional leasehold, plus an allocated percentage of the costs of New Dominion’s land personnel engaged in activities relating to the Eight East area of mutual interest. The Eight East Participation Agreement permits New Dominion to hold record title to any undeveloped leasehold within the Eight East area of mutual interest that it acquires pending these quarterly assignments. Although New Dominion would hold record title to any such undeveloped leasehold, the Eight East Participation Agreement requires the assignment to us of the leasehold quarterly or upon the earlier commencement of development, and it is this right on which we rely in connection with estimating any proved undeveloped reserves associated with such acreage in our reserve reports. Each party to the Eight East Participation Agreement has the option, but not the obligation, to participate in future wells proposed by the contract operator for its proportionate share of the costs associated with such wells. The parties also have agreed to pay New Dominion their proportionate share of a $25,000 development fee for each well in which they participate upon spud of the well. In addition, the parties have agreed to reimburse New Dominion quarterly for their proportionate share of New Dominion’s costs to dispose of saltwater from the wells in which they participate, as well as their proportionate share of infrastructure and equipment costs incurred on a well-by-well basis, along with a fee to New Dominion of 10% of such costs. While New Dominion remains the sole owner of the saltwater disposal infrastructure servicing the Eight East area, the participants have a priority right of access to this disposal infrastructure.

In the event that New Dominion acquires additional leasehold acreage for the benefit of the parties to the Eight East Participation Agreement (including by means of forced pooling), New Dominion will assign record title to the other parties to the Eight East 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 18.75% less any existing royalties or overriding royalty interests that burden the applicable lease; however, if existing royalties and overriding royalty interests exceed 18.75% 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 Eight East 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 Eight East Participation Agreement shall be limited to only those depths and formations so acquired by New Dominion.

The Eight East 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 in which we elect to participate. If we decline to participate in a new well that New Dominion proposes, we will not be eligible to participate in any other wells drilled in the same section, 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 development costs. The Eight East Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs

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for wells in which we elect to participate within 30 days of a new well notice from the contractor at least five days prior to the spud date for the new well, depending on which event occurs earlier.

In return for serving as the contract operator of the Eight East area, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Eight East 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.

In June 2014, the Eight East Participation Agreement was amended to provide for the construction of a natural gas pipeline and gathering and transportation system, whereby we agreed to reimburse New Dominion for our proportionate share of costs incurred to construct the system.

Southern Dome Participation Agreement

In connection with the Southern Dome Acquisition and another acquisition of additional interests in those properties from a third party in the first quarter of 2014, we succeeded to Scintilla’s and such third party’s rights and obligations under the Southern Dome Participation Agreement (we refer to the Golden Lane Participation Agreement, the Luther JOA, the Eight East Participation Agreement and the Southern Dome Participation Agreement collectively as the “Participation Agreements”). The other parties to the Southern Dome Participation Agreement include New Dominion, as contract operator, and an unaffiliated third party that also owns a working interest in the Southern Dome field.

The Southern Dome Participation Agreement controls the development and operation of the Southern Dome field and provides New Dominion, as contract operator, with authority to control the development and operation of the field. New Dominion also is empowered to acquire additional leasehold within the Southern Dome field for the account of the working interest owners in exchange for quarterly reimbursement by the working interest owners of their proportionate shares of the costs of such additional leasehold plus a fee to New Dominion of 15% of such costs. The Southern Dome Participation Agreement permits New Dominion to hold record title to any undeveloped leasehold within the Southern Dome area of mutual interest that it acquires in the future for the benefit of the parties to the Southern Dome Participation Agreement until such time as development of the applicable leasehold commences. Although New Dominion would hold record title to any such undeveloped leasehold, the Southern Dome 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 held or acquired by New Dominion in the Southern Dome area of mutual interest for our benefit in our reserve reports. Each party to the Southern Dome Participation Agreement has committed to participate in future wells proposed by the contract 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 a monthly project management fee, which varies based the average daily production from the Southern Dome interests; the current fee is $15,000 per month. In addition, the parties have agreed to reimburse New Dominion for their proportion share of New Dominion’s costs to install, maintain and operate a saltwater disposal system servicing the Southern Dome field, although New Dominion remains the sole owner of this saltwater disposal system.

In the event that New Dominion acquires additional leasehold acreage for the benefit of the parties to the Southern Dome Participation Agreement (including by means of forced pooling) and subsequently commences development, New Dominion will assign record title to the other parties to the Southern Dome 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 Southern Dome 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 Southern Dome Participation Agreement shall be limited to only those depths and formations so acquired by New Dominion.

The Southern Dome 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 Southern Dome Participation Agreement contains significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreement. If a party declines to participate in a new well that New Dominion proposes, such party will not be eligible to participate in any further new wells proposed under the Southern Dome Participation Agreement, 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 of such well. In addition, if a party

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declines to participate in a new well that New Dominion proposes, such party will relinquish its interest in the new well and any other new wells proposed under the Southern Dome Participation Agreement and its share of production from such new wells. The Southern Dome Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs, acreage costs and saltwater disposal fees within 30 days of a new well notice from the contract operator at least five days prior to the spud date for the new well, depending on which event occurs later. We also are obligated to pay our share of certain costs in advance of drilling a new well or other operations being conducted within 15 days of notice from the contract operator when such costs exceed $100,000.

In return for serving as the contract operator of the Southern Dome field, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Southern Dome 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.

SEASONAL NATURE OF BUSINESS

The price we receive for our oil, natural gas, and NGL production is impacted by seasonal fluctuations in demand. The demand for oil, natural gas, and NGL typically peaks during the coldest months and tapers off during the warmest months, with a slight increase during the summer to meet the demands of electric generators. The weather during any particular season can affect this cyclical demand for natural gas. Seasonal anomalies such as mild winters or hot summers can lessen or intensify this fluctuation. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. Seasonal changes in weather and significant weather events can temporarily affect the delivery of oilfield services. However, we currently do not believe that seasonal fluctuations will have a material impact on our oilfield services business in the foreseeable future.

ENVIRONMENTAL AND OIL AND NATURAL GAS INDUSTRY REGULATIONS

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil, natural gas, and NGL 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, natural gas, and NGL production have statutory provisions regulating the exploration for and production of oil, natural gas, and NGL, 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, natural gas, and NGL 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 our contract operator'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 United States Environmental Protection Agency ("EPA"), the United States Commodities Futures Trading Commission ("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 oil and NGL are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of 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 1992”) 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 oil and refined products (collectively referred to as

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“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

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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, natural gas, and NGL 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, natural gas, and NGL wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil, natural gas, and NGL 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 NGL 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, 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 United States Circuit Court of Appeals vacated the order with respect to major non-interstate pipelines.

In May 2010, 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. 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 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.

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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 United States Congress and was passed by the United States House of Representatives in 2010, but was not voted on in the United States 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.

Environmental matters and occupational safety and health

New Dominion’s exploration, production and processing operations on our behalf in addition to our oilfield services operations on behalf of third-party exploration and production operators are subject to stringent federal, regional, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. As with the oil and natural gas sector generally, compliance with current and expected environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain and upgrade equipment and facilities. These laws and regulations may, among other things, require the acquisition of various permits to conduct regulated activities, require the installation of pollution control equipment or otherwise restrict the way wastes may be handled or disposed; limit or prohibit construction activities in sensitive areas such as wetlands, wilderness or urban areas or areas inhabited by endangered or threatened species, impose specific health and safety criteria addressing worker protection, require investigatory and remedial action to mitigate pollution conditions caused by current operations or attributable to former operations; and enjoin some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in assessment of administrative, civil and criminal sanctions including penalties, the imposition of removal or remedial obligations and the issuance of injunctions limiting or prohibiting some or all of our activities.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, any changes in environmental laws and regulations or reinterpretation of enforcement policies that result in more stringent and costly well drilling, construction, completion or water management activities, or waste handling, storage, transport disposal or remediation requirements could have a material adverse effect on our contract operator’s and our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of operations and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property or natural resources or injury to persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current legal requirements would not have a material adverse effect on us, there is no assurance that we will be able to remain in compliance in the future with such existing or any new laws and regulations or that such future compliance will not have a material adverse effect on our business and results of operations.

The following is a summary of the more significant existing environmental and worker safety and health laws and regulations to which New Dominion’s business operations are subject on our behalf or we are subject in our oilfield services business and for which compliance may have a material adverse impact on our contract operator’s and our capital expenditures, results of operations or financial position.

Hazardous substances and wastes

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“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, New Dominion and our oilfield services business generate materials that may be regulated as hazardous substances. In addition, the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and their implementing regulations regulate the generation, storage, treatment, transportation, disposal and cleanup of hazardous and non-hazardous 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 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 costs to manage and dispose of wastes generated by New Dominion and third-party exploration and production operators for whom we conduct oilfield services, which could have a material adverse effect on New

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Dominion’s and our results of operations and financial position. In the course of New Dominion’s operations and our oilfield services business' operations, some amounts of ordinary industrial wastes are generated that may be regulated as hazardous wastes. Because of historical and/or current operating practices upon our properties by New Dominion and/or third-party predecessor owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under New Dominion’s or our control, those properties may have become impacted and may be subject to CERCLA, RCRA and analogous state laws. Under such laws, New Dominion 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.

Water discharges and subsurface injections

The Federal Water Pollution Control Act, as amended, which also is known as the Clean Water Act (“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. 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 CWA. 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.

The Oil Pollution Act of 1990, as amended (“OPA”) amends the CWA and establishes strict liability standards for owners and operators of facilities that are the site of a release of oil into waters of the United States 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 OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the United States. OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages. OPA also 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.

Operations associated with New Dominion’s production and development activities generate drilling muds, produced waters and other waste streams, some of which may be disposed of by means of injection into underground wells situated in non-producing subsurface formations. These injection wells are regulated by the federal Safe Drinking Water Act (the “SDWA”) and analogous state laws. The underground injection well program under the SDWA requires permits from the EPA or analogous state agency for disposal wells that we operate, establishes minimum standards for injection well operations, and restricts the types and quantities of fluids that may be injected. Any changes in applicable laws or regulations or the inability to obtain permits for new injection wells in the future may affect New Dominion’s ability to dispose of produced waters and ultimately increase the cost of their and our operations, which costs could be significant. In addition, there exists a growing concern that the injection of saltwater into below ground disposal wells triggers seismic activity in certain areas, including Oklahoma, where New Dominion conducts operations on our behalf. As a result, the Oklahoma Corporation Commission approved new regulations effective in September 2014 to increase monitoring requirements for state disposal wells located in certain seismically-active areas, which rules require operators of disposal wells located in the Arbuckle Formation to record injection pressure and volume measurements on a daily basis and provide such data to the OCC upon request, and further requires, as part of its agency practice, that disposal wells within a six mile radius of designated seismic “areas of interest,” regardless of formation, have their pressures and volumes recorded on a daily basis and provided to the OCC upon request. Also, in September 2014, the governor of Oklahoma announced the creation of a Coordinating Council on Seismic Activity, which is intended to help researchers, policymakers, regulators and oil and natural gas industry study seismicity in the state. The Utility and Environment Committee of the Oklahoma House of Representatives also held an interim study to examine what, if any, correlations exist between wastewater disposal wells and seismic activity in the state. Although the committee did not recommend any policies, procedures or legislative items on the basis of the interim study, this does not foreclose the possibility of new law or regulations in the future.

Hydraulic fracturing

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EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the federal Bureau of Land Management (“BLM”) issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, a growing number of states have adopted, including Oklahoma where New Dominion conducts operations on our behalf, or are considering legal requirements that could impose more stringent permitting, disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that New Dominion follows applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nevertheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where New Dominion operates, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, which could have an adverse impact on our results of operation and financial position. Also, if such new or more stringent legal requirements were imposed on third-party exploration and production operators, some of whom are our customers with respect to our oilfield services business, they could similarly experience such increased costs of operations, delays or curtailments in the pursuit of exploration, development and production activities, or be precluded from drilling activities, any one or more of which developments could result in a reduced demand for our oilfield services business.

In addition, several governmental reviews are underway that focus on environmental aspects of hydraulic fracturing activities. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. In addition, EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in the first half of 2015. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from New Dominion’s hydraulic fracturing operations. We have insurance policies in effect that are intended to provide coverage for our losses solely related to New Dominion’s hydraulic fracturing operations and we believe our pollution liability and excess liability insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

Activities on federal lands

Oil, natural gas, and NGL exploration and production activities on federal lands, including Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an EA that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, New Dominion has minimal exploration and production activities on federal lands. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. Similarly, third-party exploration and production operators conducting operations on federal lands and for whom we conduct oilfield services must also comply with the requirements of NEPA. The NEPA process has the potential to delay or limit, or increase the cost of, the development of oil, natural gas, and NGL projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

Endangered Species Act considerations

Environmental laws such as the Endangered Species Act, as amended (“ESA”), may impact exploration, development and production activities on public or private lands. The ESA provides broad protection for species of fish, wildlife and plants that are listed as threatened or endangered in the United States, and prohibits taking of endangered species. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While

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some of our properties may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. If endangered species are located in areas of the properties where New Dominion wishes to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Third-party exploration and production operators conducting operations in areas where endangered species are located and for whom we conduct oilfield services could also incur similar delays or restrictions in the work to be performed or increased mitigative costs to comply, which developments could reduce the need for our oilfield services.

Moreover, as a result of a settlement approved by the United States District Court for the District of Columbia in September 2011, the United States Fish and Wildlife Service ("FWS") is required to make a determination on listing of numerous species as endangered or threatened under the ESA by no later than September 30, 2017. The designation of previously unprotected species as threatened or endangered in areas where operations are conducted on our behalf in the case of New Dominion's activities or conducted by third-party exploration and production operators for whom we conduct oilfield services could cause any of them to incur increased costs arising from species protection measures or could result in limitations on our contract operator’s exploration and production activities that could have an adverse impact on their ability to develop and produce reserves, which could have a significant adverse effect on our results of operations and financial position with respect to our production interests and our oilfield services business. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Oklahoma where New Dominion conducts operations on our behalf, and in Oklahoma, Texas, New Mexico and Kansas, where we conduct oilfield services for our customers, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies (“WAFWA”), pursuant to which such parties agreed to take steps to protect the lesser prairie chicken’s habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken’s habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to New Dominion and to third-party exploration and production operators, some of whom are our customers in the oilfield services business, from species protection measures, time delays or limitations on operations, which costs, delays or limitations may be significant to New Dominion’s and our business segments.

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, natural gas, and NGL projects. Covered emissions sources of New Dominion 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. Similarly, third-party exploration and production operators with covered emissions subject to similar laws or regulations and for whom we conduct oilfield services could also incur added capital expenditures over the next several years to comply with such legal requirements. For example, in December 2014, the EPA published a proposed regulation that it expects to finalize by October 1, 2015 that would revise the National Ambient Air Quality Standard for ozone, recommending a standard between 65 to 70 parts per billion (“ppb”) for both the 8-hour primary and secondary standards protective of public health and public welfare. If the EPA lowers the ozone standard, states could be required to implement new more stringent regulations, which could, among other things, require installation of new emission controls on certain sources of emissions. Compliance with these requirements could increase New Dominion's and our third-party customers' costs of development and production, which costs could be significant and, in the case of our oilfield services business, could reduce demand for our business.

Climate change

Based on findings made by the EPA that emissions of carbon dioxide, methane and other greenhouse gases (“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 GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by the states. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil, natural gas, and NGL production sources in the United States on an annual basis, which include certain of New Dominion operations. These EPA rulemakings could adversely affect New Dominion's operations and the operations of third-party exploration and production operators, some of whom are

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customers of our oil field services business, and also restrict or delay any of their ability to obtain air permits for new or modified sources.

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 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 Dominion operations and our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from New Dominion’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, natural gas, and NGL that are produced by New Dominion on our behalf. Similar increases in costs and reduced demand for business could arise with respect to our third-party exploration and production operator customers for whom we conduct oilfield services. For example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025.

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 New Dominion or third-party customers for whom we conduct oilfield services to incur significant costs in preparing for or responding to those effects, which development could have a significant adverse effect on our financing and results of operations.

Worker safety and health

In the performance of exploration and production operations on our behalf, our contract operator 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. Our oilfield services business is similarly subject to the requirements of OSHA and comparable state standards. 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 New Dominion and our oilfield services business organize and/or disclose information about hazardous materials used or produced in those operations and that this information be provided to their employees, state and local governmental authorities and citizens. In connection with the performance of these operations, we believe that our contract operator and our oilfield services business are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

MANAGEMENT

We are managed and operated by the board of directors and executive officers of our general partner. For the year ended December 31, 2014, our general partner provided management and administrative services that we believe are necessary to operate, manage and grow our business. For more information about the directors and officers of our general partner, see “Directors, Executive Officers and Corporate Governance - Management” in Part III, Item 10 of this report.

EMPLOYEES

As of December 31, 2014, our general partner had 15 full-time employees supporting the operation of our oil and natural gas properties and our subsidiary businesses. Our oilfield services subsidiaries had 412 full-time employees. None of these employees are represented by a labor union or covered by any collective bargaining agreement. We believe that relations with these employees are satisfactory.

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INSURANCE

As is common in the oil and natural gas industry, we do 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.



ITEM 1A.	RISK FACTORS

Our business has many risks. Factors that could materially adversely affect our business, financial position, operating results or liquidity and the trading price of our common units are described below. This information should be considered carefully, together with other information in this Annual Report on Form 10-K and other reports and materials we file with the SEC.

Risks Related to Our Business

At times, we have made or may make distributions at levels that are below the minimum quarterly distribution per common unit established under our partnership agreement, and we cannot predict when we may have sufficient cash available 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.

At times, we have made or may make distributions at a level that is below the $0.525 per unit minimum quarterly distribution per common unit established in our partnership agreement, and we cannot predict when we may have sufficient available cash in a given quarter to pay the minimum quarterly distribution per unit. 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, growing our oilfield services business, 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 level of drilling activity and demand for our oilfield services;


•	the amount of oil, natural gas and NGL 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;


•	the level of cash reserves for future operating or capital needs that the board of directors may determine is appropriate ; 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, see "Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities” in Part II, Item 5 of this report.

Commodity prices are volatile, and continued low levels of or further declines 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 NGL heavily influences our revenue, profitability, access to capital and future rate of growth. Oil, natural gas and NGL 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, natural gas, and NGL have been volatile, as demonstrated in the fourth quarter of 2014 and into 2015. These markets will likely continue to be volatile in the future. The prices

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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 NGL;


•	the price and quantity of imports of foreign oil, natural gas, and NGL;


•	the level of global oil, natural gas, and NGL exploration and production;


•	the level of global oil, natural gas, and NGL 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, natural gas, and NGL futures contracts;


•	price and availability of competitors’ supplies of oil, natural gas, and NGL;


•	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 67% of our estimated proved reserves as of December 31, 2014 were oil and NGL reserves, our financial results are more sensitive to movements in oil and NGL prices. The price of oil has been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2014, the daily NYMEX West Texas Intermediate oil spot price ranged from a high of $107.95 per Bbl to a low of $53.45 per Bbl, and the NYMEX natural gas Henry Hub spot price ranged from a high of $8.15 to a low of $2.74 per MMBtu.

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

As our oilfield services business and financial performance depends on the level of drilling and completion activity in the oil and natural gas industry, which is typically dependent on commodity prices, downturns in the oil and natural gas industry or in the oilfield services business and declines in commodity prices may reduce demand for our oilfield services and have a material adverse effect on our financial condition or results of operations.

Continued low levels or further commodity price declines may result in reductions of the asset carrying values of our oil and natural gas properties.

We utilize the full cost method of accounting for costs related to oil and natural gas properties. Under this accounting method, all costs for both productive and nonproductive properties are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. However, the amount of these costs that can be carried as capitalized assets is subject to a ceiling, which limits such pooled costs to the aggregate of the present value of future net revenues of proved natural gas and oil reserves attributable to proved properties, discounted at 10%, plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the unweighted arithmetic average of the first-day-of-the-month prices for oil, natural gas and NGL in effect at the end of the quarter, adjusted for the impact of derivatives accounted for as cash flow hedges. As none of our derivatives are accounted for as cash flow hedges, the impact of our derivative contracts has been excluded from the determination of our full cost ceiling. Continued low levels or further declines in oil, natural gas and NGL prices without other mitigating circumstances, are expected to result in additional losses of future net revenues, including

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losses attributable to quantities that cannot be economically produced at lower prices, which could cause us to make additional write-downs of capitalized costs of our natural gas and oil properties and non-cash charges against future earnings. The amount of such future write-downs and non-cash charges could be substantial. If commodity prices remain at the current, depressed levels or decline further, we expect we would have reductions in our asset carrying value for our oil and natural gas properties in multiple quarters in 2015.

If we are unable to successfully integrate and manage businesses that we have acquired and any businesses acquired in the future, our results of operations and financial condition could be adversely affected.

One of our business strategies is to acquire operations, assets and technologies that are complementary to our existing businesses. There are financial, operational and legal risks inherent in any acquisition strategy, including:


•	unexpected costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including environmental liabilities;


•	limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business, in order to comply with public reporting requirements;


•	potential losses of key employees and customers of the acquired businesses;


•	inability to commercially develop acquired technologies;


•	increased financial leverage;


•	ability to obtain additional financing or issue additional securities;


•	increased expenses, working capital requirements and/or unitholder distributions; and


•	difficulties involved in combining disparate company cultures and facilities.

The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, results of operations and financial condition.

Our oilfield services customer base is concentrated and the loss of, or nonperformance by, one or more of our significant customers could cause our revenue to decline substantially.

Our top two oilfield services customers accounted for approximately 14% and 11%, respectively, of our total oilfield services segment sales for the year ended December 31, 2014. It is likely that we will continue to derive a significant portion of our oilfield services revenue from a relatively small number of customers in the future. If a major customer decided not to continue to use our services or significantly reduces its drilling plans, our revenue would decline and our operating results and financial condition could be harmed. In addition, we are subject to credit risk due to the concentration of our customer base. Any increase in the nonpayment of and nonperformance by our counterparties, either as a result of changes in financial and economic conditions or otherwise, could have a material effect on our business, results of operations and financial condition and could adversely affect our liquidity.

Our oilfield services business and financial performance depends on the level of drilling and completion activity in the oil and natural gas industry in the United States. Demand for our services may be adversely affected if this activity slows due to industry conditions that are beyond our control, such as low commodity prices or reduced demand for crude oil and natural gas.

We provide services to companies in the oil and natural gas exploration and production industry, an industry with activity levels that are significantly affected by the levels and volatility of oil and natural gas prices. The demand for our services is impacted in part by current and anticipated oil and natural gas prices. From January 2011 until July 2014, oil prices have generally ranged between $90.00 - $100.00 per barrel. During the same period, natural gas prices have generally remained in the range of $2.50 -

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$4.50 per MMBtu. During the year ended December 31, 2014, the daily NYMEX West Texas Intermediate oil spot price ranged from a high of $107.95 per Bbl to a low of $53.45 per Bbl, and the NYMEX natural gas Henry Hub spot price ranged from a high of $8.15 to a low of $2.74 per MMBtu. Recent declines and volatility in oil and natural gas prices have reduced demand for our services, and adversely impacted our business.

If oil and natural gas prices remain volatile, or if oil and natural gas prices remain low or decline further, then drilling and completion activity may decline further and continue to erode demand for our services. Additional erosion in demand for the services we provide will adversely impact our business, financial condition, including impairment of fixed and intangible assets, and results of operations.

Drilling and completion activity in the oil and gas industry and demand for our services are influenced by numerous factors over which our management has no control, such as:


•	the supply of and demand for crude oil and natural gas;


•	the level of prices, and expectations about future prices, of crude oil and natural gas;


•	the cost of exploring for, developing, producing and delivering crude oil and natural gas, including fracturing services;


•	the expected rate of decline of current crude oil and natural gas production;


•	the discovery rates of new crude oil and natural gas reserves;


•	available pipeline and other transportation capacity;


•	lead times associated with acquiring equipment and products and availability of personnel;


•	weather conditions and natural disasters;


•	domestic and worldwide economic conditions;


•	contractions in the credit market;


•	political instability in certain crude oil and natural gas producing countries;


•	the continued threat of terrorism and the impact of military and other action, including military action in the Middle East and other parts of the world;


•	governmental regulations, including environmental protection laws and income tax laws or government incentive programs relating to the crude oil and natural gas industry and the policies of governments regarding the exploration for and production and development of their crude oil and natural gas reserves;


•	the level of crude oil production by non-OPEC countries and the available excess production capacity within OPEC;


•	crude oil refining capacity and shifts in end-customer preferences toward fuel efficiency;


•	potential acceleration in the development, and the price and availability, of alternative fuels;


•	the availability of water resources for use in hydraulic fracturing operations;


•	public pressure on, and legislative and regulatory interest in, federal, state, and local governments to ban, stop, significantly limit or regulate hydraulic fracturing operations;


•	technical advances affecting energy consumption;


•	the access to and cost of capital for crude oil and natural gas producers;


•	merger and divestiture activity among crude oil and natural gas producers; and

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•	the impact of emerging or changing laws and regulations, including environmental and safety requirements and policies.

Any of the above factors could generally depress the level of natural gas and oil exploration, development, production and well completion activity and result in a corresponding decline in the demand for the services we provide, which could have a material adverse effect on our business, results of operations and financial condition.

Our oilfield services business depends upon our ability to obtain equipment and parts from third-party suppliers, and we may be vulnerable to delayed deliveries and future price increases.

We purchase equipment and parts from third-party suppliers. At times during the business cycle, there is a high demand for oilfield services and extended lead times to obtain equipment needed to provide these services. Should our current suppliers be unable or unwilling to provide the necessary equipment and parts or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of our services could have a material adverse effect on our business, financial condition, results of operations, cash flows and cash available for distribution. In addition, future price increases for this type of equipment and parts could negatively impact our ability to purchase new equipment to update or expand our existing fleet or to timely repair equipment in our existing fleet.

New Dominion serves as the operator for all of our properties. If New Dominion fails to perform or inadequately performs or if we have a material dispute with New Dominion, 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 our contract operator, under which we rely on it to operate all of our existing producing wells and coordinate our development drilling program. For example, pursuant to our development agreement with our contract operator, our general partner has the ability to propose an annual drilling schedule as well as to determine our annual maintenance drilling budget. While under the terms of the development agreement, our contract operator 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, our contract operator 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, our contract operator may propose additions, substitutions or deletions subject to the approval of our general partner. Changes to either the budget or the drilling schedule could result from non-participation elections from other parties to the participation agreements, 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.

Although we monitor our cost and work with our contract operator to actively manage our expenses, we have seen a significant rise in our lease operating expenses compared to last year. Our lease operating expenses increased $6.0 million, or 47.4%, to $18.6 million in 2014 from $12.6 million in 2013 primarily due to the acquisition of oil and natural gas properties and increased contract operator fees and vendor costs. In addition, we are currently engaged in litigation with New Dominion and its affiliates. Recently, New Dominion has withheld revenue otherwise payable to us for various reasons. See "2015 Outlook" in Part II, Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operation" and "Note 15 - Commitments and Contingencies” to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for discussion of this litigation.

Producing oil, natural gas, and NGL reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil, natural gas, and NGL reserves and production and therefore our cash flow and ability to make distributions are 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.

Unless we replace the oil, natural gas, and NGL 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 grow or even make our 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, natural gas, and NGL production and, therefore, our cash flow from operations are highly dependent upon the level of success we have in finding or acquiring additional reserves. However, we cannot

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assure you that our future activities will result in any specific amount of additional proved reserves 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, 2014 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 9.0% 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 we conduct other successful exploration and development activities or we acquire properties containing proved reserves, or both. In addition, estimates of maintenance capital expenditures may not be sufficient to maintain production.

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 our contract operator. Other than as provided in the 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 our contract operator 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 participation agreements contain terms that may be disadvantageous to us.

In connection with our entry into the development agreement with our contract operator, 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 our contract operator has agreed to use its commercially reasonable best efforts to comply with each, it has the sole right to propose new wells under the Golden Lane Participation Agreement. Similarly, our contract operator has the sole right to propose new wells under the other participation agreements. In addition, our contract operator has the ability to propose changes to either our annual maintenance drilling budget or the drilling schedule under the development agreement, with such changes being subject to the approval of our general partner. In addition, the participation agreements contain negotiated terms that may depart from those typical in operating agreements, which grants our contract operator a high degree of control over the development of the properties. Such terms include the following:


•	with few exceptions, the contract operator may retain record title to our interest in any undeveloped properties that it acquires in the future for our benefit until after the drilling of and production from such properties.


•	subject to our general partner’s approval in certain circumstances, the 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 the contract operator proposes, we will not be eligible to participate in certain additional wells 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 the contract operator proposes, we will relinquish our interest in the new well and our share of production from the new well at least for a period of time intended to compensate other parties for our election not to participate.

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•	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, certain parts of 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 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 properties to other ventures is limited by rights held by our contract operator.

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

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.

One of our principal growth strategies is to pursue selective acquisitions of producing and proved undeveloped properties in conventional resource reservoirs. If we choose to participate in an acquisition, 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 contractually assume environmental and other risks and liabilities in connection with the acquired properties.

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

Most of our oil and gas properties are currently located 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, natural gas, and NGL 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 or non-occurrence, as appropriate, of any of these events could significantly reduce our revenues or cause substantial losses,

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impairing our future operating results. We may become subject to liability for pollution, blowouts 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.

Our exploration and production segment’s business relies on the ability to commercially develop conventional resource reservoirs using specialized processes employed by New Dominion. One technique utilized by New Dominion is the installation of electric submersible pumps to depressurize the targeted hydrocarbon-bearing reservoir, allowing the gas to expand and push oil, natural gas, and NGL out of the pores in which they are trapped, in order to increase the production of oil, natural gas, and NGL. 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, natural gas, and NGL 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 may be subject to claims for personal injury and property damage, which could materially adversely affect our financial condition, results of operations and cash available for distribution.

In our oilfield services business, we operate with most of our customers under master service agreements ("MSAs"). We endeavor to allocate potential liabilities and risks between the parties in the MSAs. Generally, our customers agree to indemnify us against claims arising from their employees’ personal injury or death to the extent that their employees are injured or their properties are damaged by such operations, unless resulting from our gross negligence or willful misconduct. Similarly, we generally agree to indemnify our customers for liabilities arising from personal injury to or death of any of our employees, unless resulting from gross negligence or willful misconduct of the customer. In addition, our customers generally agree to indemnify us for loss or destruction of customer-owned property or equipment and in turn, we agree to indemnify our customers for loss or destruction of property or equipment we own. Losses due to catastrophic events, such as blowouts, are generally the responsibility of the customer. However, despite this general allocation of risk, we might not succeed in enforcing such contractual allocation, might incur an unforeseen liability falling outside the scope of such allocation or may be required to enter into an MSA with terms that vary from the above allocations of risk. As a result, we may incur substantial losses that could materially and adversely affect our business, results of operations, financial condition and cash available for distribution.

Our oilfield services operations are subject to hazards inherent in the oil and natural gas industry, which could expose us to substantial liability and cause us to lose customers and substantial revenue.

Risks inherent to our industry, such as equipment defects, vehicle accidents, fires, explosions, blowouts, surface cratering, uncontrollable flows of gas or well fluids, and various environmental hazards such as oil and completion fluid spills and releases of, and exposure to, hazardous substances, could expose us to substantial liability, including environmental liability, and cause us to lose customers and substantial revenue. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In particular, our customers may elect not to purchase our services if they view our environmental or safety record as unacceptable, which could cause us to lose customers and substantial revenues.

The cost of managing such risks may be significant. 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. Our insurance may not be adequate to cover all losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we do not or are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations, cash flows and cash available for distribution. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which could have a material adverse effect on our business, results of operations and financial condition.

Competition in the oil and natural gas industry may affect our ability to market our oilfield services.

The oilfield services industry is highly competitive and fragmented. On the one hand, we compete against several large companies that possess and employ financial, technical and personnel resources substantially greater than our resources. Larger oilfield services companies may benefit from a longer operating history and greater name recognition as well as be able to offer

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potential customers a broader range of services, products and technical expertise. Further, larger competitors may be better able to withstand sustained periods of poor financial results and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. On the other hand, due to the low initial barriers to entry in the oilfield services industry, we face competition from numerous small companies capable of competing effectively on a regional or local basis. Smaller competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Such competition could reduce or inhibit the expansion of our market share or restrict our ability to increase or maintain our prices for our present services, which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

In addition, some contracts are awarded on a bid basis, which further increases competition based on price. Pricing is often the primary factor in determining which qualified contractor is awarded such jobs. The competitive environment may be further intensified by mergers and acquisitions among oil and natural gas companies or other events that have the effect of reducing the number of available customers. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Some exploration and production companies have begun performing hydraulic fracturing and directional drilling on their wells using their own equipment and personnel. Any increase in the development and utilization of in-house fracturing and directional drilling capabilities by our customers could decrease the demand for our services and have a material adverse impact on our business.

If we are not able to acquire new oilfield services equipment or our equipment becomes technologically obsolete, our results of operations may be adversely affected.

The market for oilfield services is characterized by changing technology and product introduction. As a result, our success is dependent upon our ability to acquire new services and equipment on a cost-effective basis and to introduce them into the marketplace in a timely manner. While we intend to continue committing substantial financial resources and effort to the development of new services and equipment, we may not be able to successfully differentiate our services from those of our competitors. Our clients may not consider our proposed services to be of value to them; or if the proposed services are of a competitive nature, our clients may not view them as superior to our competitors' services and products. In addition, we may not be able to adapt to evolving markets and technologies or achieve and maintain technological advantages.

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 Kristian B. Kos and Dikran Tourian) 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, natural gas, and NGL 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 Kristian B. Kos and Dikran Tourian) 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 may be unable to attract and retain skilled and technically knowledgeable employees, which could adversely affect our business.

Our success depends upon attracting and retaining highly skilled professionals and other technical personnel. A number of our employees are skilled and trained in specialized areas, and our failure to continue to attract and retain such individuals could adversely affect our ability to compete in the exploration, production and oilfield services industries. We may confront significant and potentially adverse competition for these skilled and technically knowledgeable personnel, particularly during periods of increased demand for oil, natural gas, and NGL. Additionally, at times there may be a shortage of skilled and technical personnel available in the market, potentially compounding the difficulty of attracting and retaining these employees. As a result, our business, results of operations and financial condition may be materially adversely affected.

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We rely on our contract operator 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 or operational regulations may impact our contract operator’s ability to handle saltwater.

The proposed production is dependent on economically disposing of large amounts of saltwater utilizing our contract operator’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 as well as result in delays in production activities. For example, as a result of growing concern that the injection of saltwater into below ground disposal wells triggers seismic activity in certain areas, including Oklahoma, where New Dominion conducts operations on our behalf, the Oklahoma Corporation Commission approved new regulations effective in September 2014 to increase monitoring requirements for state disposal wells in certain seismically-active areas, which rules require operators of disposal wells located in the Arbuckle Formation to record injection pressure and volume measurements on a daily basis and provide such data to the OCC upon request, and further requires, as part of its agency practice, that disposal wells within a six mile radius of designated seismic “areas of interest,” regardless of formation, have their pressures and volumes recorded on a daily basis and provided to the OCC upon request. In another example, in September 2014, the governor of Oklahoma announced the creation of a Coordinating Council on Seismic Activity, which is intended to help researchers, policymakers, regulators and oil and natural gas industry study seismicity in the state. The Utility and Environment Committee of the Oklahoma House of Representatives also held an interim study to examine what, if any, correlations exist between wastewater disposal wells and seismic activity in the state. Although the committee did not recommend any policies, procedures or legislative items on the basis of the interim study, this does not foreclose the possibility of new law or regulations in the future.

In addition, New Dominion's saltwater disposal operations have been the subject of several lawsuits alleging its disposal activities have resulted in seismic activity that has damaged property in close proximity to certain disposal wells. If, as a result of these or other lawsuits, the Oklahoma Corporation Commission or other regulatory body were to impose additional regulation on any of New Dominion's saltwater disposal wells, our oil and natural gas operations could be substantially affected.

Our ability to sell our production 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 oil, natural gas, and NGL 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. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow from operations.

Future downturns in the oil and natural gas industry, or in the oilfield services business, may have a material adverse effect on our financial condition or results of operations.

The oil and natural gas industry is highly cyclical and demand for the majority of our oilfield services is substantially dependent on the level of expenditures by the oil and natural gas industry for the exploration, development and production of oil, natural gas, and NGL reserves, which are sensitive to oil, natural gas, and NGL prices and generally dependent on the industry’s view of future oil, natural gas, and NGL prices. There are numerous factors affecting the supply of and demand for our oilfield services, which are summarized as:


•	general and economic business conditions;


•	market prices of oil, natural gas, and NGL and expectations about future prices;


•	cost of producing and the ability to deliver oil, natural gas, and NGL;

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•	the level of drilling and production activity;


•	mergers, consolidations and downsizing among our customers;


•	the impact of commodity prices on the expenditure levels of our customers;


•	financial condition of our client base and their ability to fund capital expenditures;


•	the physical effects of climatic change, including adverse weather or geologic/geophysical conditions;


•	the adoption of legal requirements or taxation relating to climate change that lower the demand for petroleum-based fuels;


•	civil unrest or political uncertainty in oil producing or consuming countries;


•	level of consumption of oil, gas and petrochemicals by consumers;


•	changes in existing laws, regulations, or other governmental actions, including temporary or permanent moratorium on hydraulic fracturing;


•	the business opportunities (or lack thereof) that may be presented to and pursued by us;


•	availability of services and materials for our customers to grow their capital expenditures;


•	ability of our customers to deliver product to market; and


•	availability of materials and equipment from our key suppliers.

The oil and natural gas industry has historically experienced periodic downturns, which have been characterized by diminished demand for our oilfield services and downward pressure on the prices we charge for these services. A significant downturn in the oil and natural gas industry could result in a reduction in demand for oilfield services and could adversely affect our operating results.

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, natural gas, and NGL 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 our reserves.

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.

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Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil, natural gas, and NGL reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. 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 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, natural gas, and NGL reserves and production and, therefore, our future cash flow and income.

Approximately 17% of our total estimated proved reserves as of December 31, 2014 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, natural gas, and NGL 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, natural gas, and NGL reserves. In accordance with SEC requirements for the years ended December 31, 2014 and 2013, 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, natural gas, and NGL;


•	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 our present value estimates.

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, natural gas, and NGL reserves.

The oil and natural gas 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, and potentially proceeds from debt and equity offerings.

If we realize lower than expected cash from production, either due to lower than anticipated production levels, a decline in commodity prices from recent levels or higher production costs, 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 our oil and natural gas 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 with respect to our properties due to lack of capital, we would be subject to substantial penalties under our

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participation agreements 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 NGL we are able to produce and sell from existing wells;


•	the prices at which our oil, natural gas and NGL 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, all of which we experienced in the fourth quarter of 2014, 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 to purchase equipment for our oilfield services business or 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.

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, natural gas, and NGL and securing equipment and trained personnel. As a relatively small company, many of our competitors are major and large independent oil and natural gas companies or diversified oilfield services companies that possess and employ financial, technical and personnel resources substantially greater than our resources. The larger exploration and production 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. Additionally, larger oilfield services companies may be able to offer potential customers a broader range of services, products and technical expertise. 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.

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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 NGL 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 CFTC, the SEC and other regulators to promulgate rules and regulations implementing the new legislation. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court (the “District Court”) for the District of Columbia in September of 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require us, in connection with covered derivatives activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions on us is uncertain at this time.

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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 full impact of the Act and related regulatory requirements upon the Partnership’s business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Act and any new regulations could significantly increase the cost of derivative contracts, 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 or 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, natural gas, and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas, and NGL. 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, natural gas, and NGL 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.

Revenues from our exploration and production segment are generated under contracts with a limited number of customers. Historically, a majority of the natural gas from our properties has been sold to Scissortail Energy, LLC and a majority of the oil from our properties has been sold to United Petroleum Purchasing Company. 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, natural gas, and NGL wells New Dominion 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, natural gas, and NGL interest in a particular prospective drilling spacing unit to apply to the Oklahoma Corporation Commission for an order forcing all other holders of oil, natural gas, and NGL 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, natural gas, and NGL exploration and development may be eliminated as a result of future legislation.

The Obama Administration’s budget proposal for fiscal year 2016 includes proposals that would, among other things, eliminate or reduce certain key United States federal income tax incentives currently available to oil, natural gas, and NGL 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, (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 proposals will be introduced into law and, if so, 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 United States federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil, natural gas, and NGL 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.

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We and our contract operator are subject to a variety of environmental and worker health and safety laws and regulations, which may result in increased costs and significant liability to our business.

We and our contract operator are subject to a variety of stringent governmental laws and regulations relating to protection of the environment, worker health and safety, the use and storage of chemicals, gases and other products used in our and our contract operator's analytical and manufacturing processes as well as our oilfield services business, and the discharge and disposal of wastes generated by those processes and services business. Certain of these laws and regulations may impose joint and several, strict liability for environmental liabilities, such as the remediation of historical contamination or recent spills, and failure to comply with such laws and regulations could result in the assessment of damages, fines and penalties, the imposition of remedial or corrective action obligations or the suspension or cessation of some or all of our operations. These stringent laws and regulations could require us or our contract operator to acquire permits or other authorizations to conduct regulated activities, install and maintain costly equipment and pollution control technologies, impose specific health and safety standards addressing work protection, or incur costs or liabilities to mitigate or remediate pollution conditions caused by New Dominion's or our operations or attributable to former owners or operators. If we or our contract operator fail to control the use, or adequately restrict the emission or discharge, of hazardous substances or wastes, we or our contract operator could be subject to future material liabilities including remedial obligations. In addition, public interest in the protection of the environment has increased dramatically in recent years with governmental authorities imposing more stringent and restrictive requirements. We anticipate that the trend of more expansive and stricter environmental laws and regulations will continue, the occurrence of which may require us or our contract operator to increase our capital expenditures or could result in increased operating expenses.

There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our contract operator’s exploration, production and processing operations on our behalf and our oilfield services operations, some of which may be material, due to our contract operator’s or our 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, we and our contract operator may be strictly 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 our contract operator 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 or our oilfield services are performed, 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 our contract operator 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 our contract operator 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, natural gas, and NGL that New Dominion produces for us or exploration and production operators, some of whom are our oilfield services customers, produce, while the physical effects of climate change could disrupt the production and result in significant costs in preparing for or responding to those effects.

Based on the EPA's determination 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, the EPA adopted regulations under the existing CAA that, among other things, establish PSD construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically will be established by the states. 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 onshore and offshore oil, natural gas, and NGL production facilities on an annual basis, which includes certain of New Dominion operations on our behalf. The EPA’s GHG rules could adversely affect the operations of New Dominion on our behalf or of exploration and production operators, some of whom are our customers in the oilfield services business, which, in the case of our customers, could reduce demand for our oilfield services business, and also restrict or delay New Dominion’s or such customers’ ability to obtain air permits for new or modified facilities.

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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 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 Dominion’s operations and our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from New Dominion’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, natural gas, and NGL that New Dominion produces on our behalf. Similar increases in costs and reduced demand for business could arise with respect to our third-party exploration and production operator customers for whom we conduct oilfield services. For example, pursuant to President Obama’s Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025.

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 New Dominion’s and our third-party oilfield services customers' 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.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil, natural gas, and NGL wells and adversely affect our production and demand for our oilfield services.

It is customary to recover natural gas from deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate gas production. The process is typically regulated by state oil and gas commissions or similar state agencies but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final CAA regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015. In addition, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, a growing number of states have adopted, including Oklahoma where New Dominion conducts operations on our behalf, or are considering legal requirements that could impose more stringent permitting, disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit hydraulic fracturing altogether, as the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local government may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where New Dominion operates, they could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells, which could have an adverse impact on our results of operation and financial position. Also, if such new or more stringent legal requirements were imposed on third-party exploration and production operators, some of whom are our customers with respect to our oilfield services business, they could similarly experience such increased costs of operations, delays or curtailments in the pursuit of exploration, development and production activities, or be precluded from drilling activities, any one or more of which developments could result in a reduced demand for our oilfield services business.

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practices. In addition, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in the first half of 2015. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.

Increasing trucking regulations may increase our costs and negatively impact our results of operations.

In connection with our oilfield services business operations, including the transportation and relocation of our oilfield service equipment, we operate trucks and other heavy equipment. As such, we operate as a motor carrier in providing certain of our services and therefore are subject to regulation by the United States Department of Transportation and by various state and local agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, driver licensing, insurance requirements, financial reporting and review of certain mergers, consolidations and acquisitions, and transportation of hazardous materials ("HAZMAT"). Our trucking operations are subject to possible regulatory and legislative changes that may increase our costs. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive or work in any specific period, onboard black box recorder device requirements or limits on vehicle weight and size.

Interstate motor carrier operations are subject to safety requirements prescribed by the United States Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state and local safety regulations that mirror federal regulations. Matters such as the weight and dimensions of equipment are also subject to federal, state and local regulations. From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Certain motor vehicle operators require registration with the Department of Transportation. This registration requires an acceptable operating record. The Department of Transportation periodically conducts compliance reviews and may revoke registration privileges based on certain safety performance criteria that could result in a suspension of operations.

Conservation measures and technological advances could reduce demand for oil and natural gas and our oilfield services.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas, resulting in reduced demand for oilfield services. The impact of the changing demand for oil and natural gas services and products could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Loss of our information and computer systems could adversely affect our business.

In our oilfield services business, we are heavily dependent on our information systems and computer based programs. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business, financial condition and results of operations.

Unionization efforts could increase our costs or limit our flexibility.

Presently, none of our employees work under collective bargaining agreements. Unionization efforts have been made from time to time within our industry, to varying degrees of success. Any such unionization could increase our costs or limit our flexibility.

We rely upon trade secrets and contractual restrictions to protect our proprietary rights. Failure to protect our intellectual property rights may undermine our competitive position, and protecting our rights or defending against third-party allegations of infringement may be costly.

Our commercial success depends on our proprietary information and technologies, know-how and other intellectual property. Because of the technical nature of our oilfield services business, we rely on trade secrets and contractual restrictions to protect our intellectual property rights. The measures we take to protect our trade secrets and other intellectual property rights may be insufficient. Failure to protect, monitor and control the use of our existing intellectual property rights could cause us to lose our competitive advantage and incur significant expenses. It is possible that our competitors or others could independently develop the same or similar technologies or otherwise obtain access to our unpatented technologies. In such case, our trade secrets would not prevent third parties from competing with us. Consequently, our results of operations may be adversely affected. Furthermore,

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third parties or our employees may infringe or misappropriate our proprietary technologies or other intellectual property rights, which could also harm our business and results of operations. Policing unauthorized use of intellectual property rights can be difficult and expensive, and adequate remedies may not be available.

In addition, third parties may claim that our products infringe or otherwise violate their patents or other proprietary rights and seek corresponding damages or injunctive relief. Defending ourselves against such claims, with or without merit, could be time-consuming and result in costly litigation. An adverse outcome in any such litigation could subject us to significant liability to third parties (potentially including treble damages) or temporary or permanent injunctions that could limit or curtail the way we conduct our business. Any adverse outcome could also require us to seek licenses from third parties (which may not be available on acceptable terms, or at all) or to make substantial one-time or ongoing royalty payments. In addition, we may not have insurance coverage in connection with such litigation and may have to bear all costs arising from any such litigation to the extent we are unable to recover them from other parties. Any of these outcomes could have a material adverse effect on our business, financial condition and results of operations.

Declining general economic, business or industry conditions may have a material adverse effect on our business, financial condition, results of operations and cash available for distribution and adversely affect our liquidity.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which oil and natural gas can be sold. Recently, the energy industry has experienced significant declines in oil and natural gas prices. Unfavorable oil and natural gas prices may render many of our customers’ development and production projects uneconomic. If the operations of our customers are affected by declining general economic, business or industry conditions, we may experience a reduction in the demand for our oilfield services. Any decrease in demand for petroleum products or for our oilfield services could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution and adversely affect our liquidity.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our oilfield services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our or our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Risks Related to Our Indebtedness

Our revolving credit facility and a term loan agreement contain 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 oil and natural gas assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.

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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 oil, natural gas and NGL reserves, which takes into account the prevailing oil, natural gas and NGL prices at such time, as adjusted for market differentials and 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.

Our borrowing base was reduced in the fourth quarter of 2014 from $102.5 million to $90.0 million and a further reduction is expected when the borrowing base is redetermined in April 2015. The precise amount of the reduction is not known at this time but the decrease could range from approximately $20 million to $30 million. Under the credit agreement, we would have approximately three months from the date of notification of a borrowing base reduction to pay any amounts outstanding in excess of the new borrowing base. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. If we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.

Further declines in or continued low commodity prices could result in a redetermination that further 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, if at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed, or 90%, 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. As of December 31, 2014, we had $83.0 million of outstanding borrowings with $7.0 million of available borrowing capacity and no available borrowing capacity before restriction on distributions occurs. In January and February 2015, the Partnership repaid $2.0 million in outstanding borrowings under the credit facility, which resulted in $81.0 million outstanding with no restrictions on our ability to pay distributions in February 2015.

Two of our wholly owned subsidiaries are party to a loan agreement that contains certain financial covenants, including fixed charge ratio and working capital. As a result of these covenants, the ability of our subsidiaries to distribute their available cash to us may be restricted.

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.

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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 NGL 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 an Investment in Us

Our Chief Executive Officer, Kristian B. Kos, owns a controlling interest in our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Mr. Kos and entities controlled by him, have limited duties and may have conflicts of interest with us, and they may favor their own interests to our detriment and that of our unitholders.

Mr. Kos owns a controlling interest in our general partner and appoints the directors of our general partner. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interests, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner, including Mr. Kos. Therefore, conflicts of interest exist and may arise in the future between our general partner and its owners and affiliates, 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 owners and affiliates over the interests of our unitholders and us. These potential conflicts include the following situations, among others:


•	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;


•	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 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;

•

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;


•	our general partner may cause us to borrow funds 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;

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•	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.

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 affiliates of our general partner, including Mr. Kos and entities he controls, are not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, affiliates of our general partner may acquire oilfield services companies, oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase any of those companies or assets.

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

For the year ended December 31, 2012, management considered the failure to identify errors in a timely manner to be material weaknesses in NSEC’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, NSEC evaluated its historical financial and operations data for further deficiencies and changed the method by which it computed its natural gas and NGL sales volumes to ensure that such volumes match the actual volumes processed by its first purchasers. NSEC also instituted additional control procedures around the research and recording of non-recurring transactions.

In connection with the audit of our consolidated financial statements for the year ended December 31, 2013 and preparation of quarterly reports in 2014, we and our independent registered public accounting firm identified material weaknesses in our internal controls over financial reporting. The material weaknesses related to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review, an inaccurate revenue cutoff on an acquired business and insufficient resources, and the lack of a sufficient number of qualified personnel to timely and appropriately account for and disclose the impact of complex, non-routine transactions in accordance with GAAP. These non-routine transactions impacted the recording of equity-based compensation, cash-flow presentations, revenue, business combination adjustments, contingent consideration and disclosures and calculation of earnings (loss) per unit. Although we have hired senior accounting and finance employees, reallocated existing internal resources and retained third-party consultants to help enhance our internal controls over financial reporting, there can be no assurance that we will remediate the material weaknesses or avoid future weaknesses or deficiencies. Any failure to remediate the material weaknesses and any future weaknesses or deficiencies or any failure to implement required new or improved controls or difficulties encountered in their implementation could cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Ineffective internal control over financial reporting could result in investors losing confidence in our reported financial information, and the trading price of our common units could be impacted. Failure to comply with Section 404 of Sarbanes-Oxley could potentially subject us to sanctions or investigations by the SEC, the Financial Industry Regulatory Authority or other regulatory authorities, as well as increasing the risk of liability arising from litigation based on securities law.

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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 auditing 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 auditing 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.

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 United States 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 United States 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 United States 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 an entity controlled by Mr. Kos. 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. Given the ownership interests of our general partner, our public unitholders do not have an ability to influence any operating decisions and will not be 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 after the subordination period has ended.

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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.

Estimated maintenance capital expenditures represent management’s estimate of the amount of capital expenditures necessary to maintain the revenue generating capabilities of its assets at current levels over the long term. Following the MCE Acquisition, management and the board of directors of our general partner changed the method of estimating maintenance capital expenditures to a calculation based on the estimated capital expenditures required to replace revenue generating assets (including production and producing reserves from our oil and natural gas operations and vehicles and other equipment from our oilfield services operations) on an individualized basis. With respect to our oil and natural gas operations, estimated maintenance capital expenditures represent the average cost to replace a barrel of oil equivalent, using the historical average finding and development costs over the preceding five-year period and the actual production volume for such period. With respect to our oilfield services operations, estimated maintenance capital expenditures represent the estimated replacement costs for current equipment whose useful lives are scheduled to be completed during the given year. 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

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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.

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, including Mr. Kos who owns a majority of our general partner through an entity he controls, from transferring all or a portion of their ownership interest in our general partner to a third party. Owners of a majority of the equity interests 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.

The cash distributions payable to the Class B Units of MidCentral Energy Partners L.P. held by affiliates of our general partner are attributable to the results of operations of our oilfield services segment and not our business as a whole.

Certain of the sellers in the acquisition of MCE, which include the Chairman and Chief Executive Officer of our general partner and the President, Chief Operating Officer and director of our general partner, retained Class B Units in MCLP in connection with the acquisition of MCE. The MCLP partnership agreement provides that the Class B Units have the right to receive an increasing percentage of quarterly distributions by MCLP of its available cash above specified thresholds. As a result, the cash distributions to which the holders of MCLP Class B Units are entitled will be attributable to the results of operations of our oilfield services segment and not our business as a whole. Consequently, the cash distributions paid to holders of the MCLP Class B Units may increase either at a rate disproportionate to the rate at which distributions on our common units increase or in situations where our common unit distributions have remained constant or decreased. For more information regarding the terms of the MCLP Class B Units, see "Note 9 - Equity” to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.

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;

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•	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.

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, natural gas, and NGL 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 99.0% to our unitholders and 1.0% to our general partner, and will result in a decrease in our minimum quarterly distribution.

Our partnership agreement allows us to add an amount equal to $11.5 million to operating surplus. 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 various other states. A unitholder could be liable for our obligations as if it were 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.

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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 United States 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:

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•	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, natural gas and NGL.

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 (23%) 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.

The New York Stock Exchange ("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. See "Directors, Executive Officers and Corporate Governance - Management of New Source Energy Partners L.P” in Part III, Item 10 of this report.

Tax Risks to Unitholders

Our tax treatment depends on our status as a partnership for United States 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

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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 or differing interpretations, possibly applied on a retroactive basis.

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

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

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

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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-United States 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-United States 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-United States persons are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-United States persons, and each non-United States person will be required to file United States federal tax returns and pay tax on its share of our taxable income. If you are a tax-exempt entity or a non-United States 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 common units actually 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 United States 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.

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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 to have 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 could 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 to have 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 United States 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. You may be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. 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 addition taxes and return filing requirements. It is your responsibility to file all United States federal, foreign, state and local tax returns.



ITEM 1B.	UNRESOLVED STAFF COMMENTS

None.



ITEM 2.	PROPERTIES

Information regarding our properties is contained in Item 1. Business.



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, natural gas, and NGL producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.

On January 12, 2015, David J. Chernicky, the owner of approximately 30.6% of our general partner, approximately 15.6% of our common units and all of our subordinated units, and his affiliated entities, Scintilla, LLC, New Source Energy Corporation and New Dominion, LLC filed a lawsuit against the Partnership, our general partner and certain current officers of our general partner, including Chairman and Chief Executive Officer, Kristian Kos, and Chief Financial Officer, Richard Finley, and certain of their affiliated entities in the District Court of Tulsa County, Oklahoma.

Refer to "Note 15 - Commitments and Contingencies" of the consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for a more detailed discussion of legal proceedings.



ITEM 4.	MINE SAFETY DISCLOSURES

Not applicable.

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PART II.



ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

Our common units are listed on the NYSE under the symbol “NSLP.” Our common units began trading on February 8, 2013 at an initial public offering price of $20.00 per common unit. As of March 6, 2015, the closing price for the common units was $7.65 per unit and there were approximately 90 unitholders of record. The number of record holders does not include holders of common units in "street names" or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories.

The following table sets forth, for the periods indicated, the high and low sales prices for our common units, as reported by the NYSE, and information regarding our quarterly distributions for the periods indicated.



	Sales Price Range per Common Unit		Distribution per Common Unit (1) (2)
	High	Low	Distribution per Common Unit (1) (2)
Year ended December 31, 2014
Fourth quarter (3)	$24.07	$6.65	$0.20
Third quarter	$27.66	$23.08	$0.585
Second quarter	$24.84	$21.43	$0.585
First quarter	$25.61	$22.20	$0.58

Year ended December 31, 2013
Fourth quarter	$24.28	$20.16	$0.575
Third quarter	$21.00	$19.61	$0.575
Second quarter	$21.29	$19.33	$0.550
First quarter (4)	$20.55	$19.19	$0.274

_____________


(1)	Represents cash distributions attributable to the quarter and declared and paid to limited partner unitholders within 45 days after quarter end.


(2)	We also paid cash distributions to our general partner with respect to its general partner interest. No distributions were made with respect to the incentive distribution rights ("IDRs") described below.


(3)	The cash distribution applicable to the fourth quarter of 2014 is below our minimum quarterly distribution ("MQD") of $0.525 per unit per our partnership agreement.


(4)	Our common units began trading on the NYSE on February 8, 2013.

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

Cash Distributions to Unitholders

We make cash distributions to unitholders on a quarterly basis, although there is no assurance of the amount of any such distributions, or if such distributions will be paid, as distributions 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 credit facility after giving effect to such distribution. See "Note 4 - Debt" to the consolidated financial statements in Item 8 “Financial Statements and Supplementary Data” of this report for additional information on the covenants under our credit facility.

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Additionally, we make cash distributions to Class B unitholders of MCLP on a quarterly basis to the extent certain target distribution levels are met. See "Note 9 - Equity" to the consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for additional information on the Class B unitholders.

Our Cash Distribution Policy

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.

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.

MCLP and its subsidiaries are obligated to distribute available cash, which is defined as the quotient obtained by dividing distributable cash flow with respect to the quarter by 1.25, to NSLP. Available cash may be subject to restrictions based on financial covenants under our existing debt agreement.

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, 100% to the common unitholders and our general partner, in accordance with their percentage interests, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;


•	second, 100% to the common unitholders and our general partner, in accordance with their percentage interests, 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, 100% to the subordinated unitholders and our general partner, in accordance with their percentage interests, 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 assumption 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. We expect that distributions otherwise payable on our subordinated units will be reserved by the board of directors of our general partner for use in growing our production. Additionally, if at the end of any quarter holders of our subordinated units are not entitled to receive a distribution on the subordinated units with respect to any quarter, then we will make distributions of available cash from operating surplus without regard to the third bullet above; in such a scenario, all remaining distributions of available cash for such quarter shall be made to the common unitholders and our general partner, in accordance with their percentage interests.

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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.

For the fourth quarter of 2014, the applicable distribution per common unit was $0.20. As this is below the MQD per the partnership agreement, the subordinated units did not receive distributions for the fourth quarter of 2014. Additionally, the subordinated units are not entitled to receive distributions until the common units receive an amount equal to the MQD and the cumulative arrearages. The subordination period ends on the first business day after all units have received the MQD for each of four consecutive quarters ending on or after December 31, 2015, or as otherwise provided for under the partnership agreement.

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, 100% to the common unitholders and our general partner, in accordance with their percentage interests, 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 assumption 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 is entitled to a percentage of all distributions that we make prior to our liquidation in an amount equivalent to its current general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its general partner interest if we issue additional units. Our general partner’s 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 general partner interest. Our general partner is entitled to make a capital contribution in order to maintain its 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% and 23%) 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 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, 100.0% to the common unitholders and our general partner, in accordance with their percentage interests, until each unitholder receives a total of $0.60375 per unit for that quarter (the “first target distribution”);


•	second, 87.0% to all unitholders and our general partner, in accordance with their percentage interests, and 13.0% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $0.65625 per unit for that quarter (the “second target distribution”); and

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•	thereafter, 77.0% to all unitholders and our general partner, in accordance with their percentage interests, and 23.0% to the holders of the incentive distribution rights, pro rata.

In connection with the MCE Acquisition, our partnership agreement was amended to provide protections in the event that the amount of incentive distributions payable with respect to any quarter exceeds the amount of incentive distributions that would have been paid to holders of the incentive distribution rights had we not received cash distributions from MCE, LP with respect to such quarter and not issued any common units in consideration for the MCE Acquisition. If such an excess occurs, payments to the general partner as holder of the incentive distribution rights will be reduced by the amount of such excess, and such excess amount shall be reserved by the general partner for use in supporting the growth of our business.

Securities Authorized for Issuance under Equity Compensation Plans

See "Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters" in Part III, Item 12 for information regarding our equity compensation plans as of December 31, 2014.

Unregistered Sales of Equity Securities

On June 26, 2014, as partial consideration for the acquisition of MidCentral Completion Services ("MCCS"), the Partnership issued 33,646 common units to the owners of MCCS valued at approximately $0.8 million, based on a value of $23.45 per unit (closing price on the date of the acquisition). The units were issued by the Partnership in a private transaction exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.

Issuer Purchases of Equity Securities

None.



ITEM 6.	SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction with Item 7 "Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8 "Financial Statements and Supplementary Data,” both contained in Part II this report.

Basis of Presentation. We were formed in October 2012. As such, we do not have historical financial operating results for periods prior to our formation. The contribution of oil and natural gas properties to us by NSEC in connection with our initial public offering ("IPO") in February 2013 was a transaction between businesses under common control. Accordingly, we have reflected such properties in our financial statements retroactively at carryover basis. The following table shows summary historical financial data attributable to such properties during the years ended December 31, 2012, 2011 and 2010, which comprised the entirety of our operating assets, during those periods.

Comparability of the information reflected in selected financial data. The comparability of the results of operations among the periods presented below is impacted by the following acquisitions:


•	oil and natural gas properties located in the Golden Lane and Luther fields in Oklahoma in March 2013;


•	oil and natural gas properties located in the Southern Dome field in Oklahoma in May 2013;


•	oil and natural gas properties located in the Golden Lane field in Oklahoma in July 2013;


•	working interests and related undeveloped leasehold rights located in the Southern Dome field in Oklahoma in October 2013 and January 2014;


•	MCE Entities, oilfield services companies, in November 2013; and


•	MCCS, EFS and RPS, oilfield services companies, in June 2014.

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	Year Ended December 31,
	2014			2013			2012			2011			2010
	(in thousands)
Statement of Operations Data:
Revenues:
Oil sales	$	14,906		$	8,090		$	5,570		$	4,489		$	5,136
Natural gas sales	15,534			10,000			6,030			8,713			9,409
NGL sales	31,048			28,847			23,996			33,058			25,909
Oilfield services	104,155			3,738			—			—			—
Total revenues	165,643			50,675			35,596			46,260			40,454
Operating costs and expense:
Oil, natural gas and NGL production	18,617			12,631			6,217			7,875			7,639
Production taxes	2,833			2,669			1,144			2,155			2,876
Cost of providing oilfield services	60,904			2,040			—			—			—
Depreciation, depletion, and amortization	54,352			18,556			14,409			14,738			14,909
Accretion	327			209			116			55			50
Impairment of goodwill and other intangible assets	59,000			—			—			—			—
General and administrative	28,671			14,760			12,660			6,928			649
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—			—			—
Total operating costs and expenses	215,673			49,265			34,546			31,751			26,123
Operating (loss) income	(50,030		)	1,410			1,050			14,509			14,331
Other income (expense):
Interest expense	(5,041		)	(4,078		)	(3,202		)	(3,735		)	(2,648		)
Gain (loss) on derivative contracts, net	10,707			(5,548		)	7,057			(1,349		)	(516		)
Gain on investment in acquired business	2,298			22,709			—			—			—
Other (expense) income	(9		)	3			—			—			—
(Loss) income before income taxes	(42,075		)	14,496			4,905			9,425			11,167
Income tax benefit (expense)	—			12,126			(1,796		)	(10,502		)	—
Net (loss) income	(42,075		)	26,622			3,109			(1,077		)	11,167
Less: net income attributable to noncontrolling interest	242			—			—			—			—
Net (loss) income attributable to New Source Energy Partners L.P.	$	(42,317	)	$	26,622		$	3,109		$	(1,077	)	$	11,167
Net (loss) income per common unit (1)	$	(2.64	)	$	2.42

_______________

(1) For the 2013 period, reflects net income per unit for the period February 13, 2013 through December 31, 2013.



	As of December 31,
	2014		2013		2012		2011		2010
	(in thousands)
Balance Sheet Data:
Total property and equipment, net	$	247,565	$	171,034	$	91,423	$	94,468	$	86,049
Total assets	$	377,465	$	254,710	$	99,934	$	104,820	$	94,539

Long-term debt, net of current maturities	$	95,218	$	80,014	$	68,000	$	68,500	$	60,000
Equity	$	211,314	$	147,253	$	15,975	$	18,420	$	27,574
Total liabilities and equity	$	377,465	$	254,710	$	99,934	$	104,820	$	94,539

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	Year Ended December 31,
	2014			2013			2012			2011			2010
	(in thousands)
Cash Flow Data:
Net cash provided by operating activities	$	44,909		$	18,364		$	27,799		$	30,133		$	27,940
Net cash used in investing activities	$	(99,653	)	$	(51,023	)	$	(12,162	)	$	(23,818	)	$	(19,226	)
Net cash provided by (used in) financing activities	$	52,957		$	39,950		$	(15,637	)	$	(6,315	)	$	(8,714	)



ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis is intended to help investors understand the Partnership’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including Part I, Item 1 "Business," Part II, Item 6 "Selected Financial Data" and Part II, Item 8 "Financial Statements and Supplementary Data." The Partnership’s discussion and analysis includes the following subjects:


•	Overview;


•	Results by Segment;


•	Results of Operations;


•	Liquidity and Capital Resources; and


•	Critical Accounting Policies and Estimates.

The 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 Part I, Item 1A "Risk Factors" of this report. 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, natural gas, and NGL, demand for our oilfield services, 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 report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See "Cautionary Statements Regarding Forward-Looking Statements" in this report.

Overview

We are a Delaware limited partnership formed in October 2012 to own and acquire oil and natural gas properties in the United States. We are engaged in the development and production of onshore oil and natural gas properties that extend across conventional resource reservoirs in east-central Oklahoma. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation. In addition, we are engaged in oilfield services through our oilfield services subsidiaries. Our oilfield services business provides essential wellsite services during drilling and completion stages of a well, including full service blowout prevention installation, pressure testing services, including certain ancillary equipment necessary to perform such services, well testing and flowback services to companies in the oil and natural gas industry primarily in Oklahoma, Texas, New Mexico, Kansas, Pennsylvania, Ohio and West Virginia.

Our business operates in two segments: (i) exploration and production and (ii) oilfield services. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions.

How We Evaluate Our Operations

We use certain financial and operational metrics to assess the specific performance of our oil and natural gas operations and our oilfield services operations.

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Oil and Natural Gas Operations


•	produced volumes;


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


•	lease operating expenses; and


•	production taxes.

Oilfield Services Operations


•	revenue; and


•	costs of providing oilfield services.

Adjusted EBITDA

We also utilize Adjusted EBITDA to monitor our performance. We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, non-cash compensation expense, non-recurring advisory fees and acquisition costs, unrealized derivative gains and losses and non-recurring gains and losses.

Our management believes Adjusted EBITDA, a non-GAAP financial measure, is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods, book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income 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. 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.

2014 Transactions

Acquisitions

In January 2014, we acquired working interests in producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma, from CEU for approximately $17.1 million, net of purchase price adjustments.

In June 2014, the Partnership acquired EFS and RPS, which are affiliated oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry, for $113.2 million.

Equity Offerings

In April 2014, we completed a public offering of 3,450,000 of our common units. From the net proceeds of approximately $76.2 million, we used $5.0 million to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes.

In October 2014, the Partnership and our general partner entered into the EDA with the Sales Agent. Pursuant to the terms of the EDA, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. On October 6, 2014, the Partnership sold 720,000 common units under the EDA for proceeds of approximately $16.2 million, net of offering costs, which included a commission to the Sales Agent of 1.75% on the principal amount of the offering. Proceeds were used to pay down a portion of the Partnership's outstanding debt and for general corporate purposes. No additional sales were made through December 31, 2014.

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Debt

In November 2014, the borrowing base on our credit facility was lowered from $102.5 million to $90.0 million, as a result of our semi-annual redetermination. The borrowing base is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas, and NGL prices, respectively. Based on our reserve estimates and using forward commodity prices, we anticipate a decrease to our borrowing base as a result of the redetermination in April 2015. Under the credit agreement, we have approximately three months from the date of notification of a borrowing base reduction to pay any amounts outstanding in excess of the new borrowing base.

2015 Outlook

Exploration and Production. As our revenue, earnings and cash flow are dependent on oil, natural gas and NGL prices, lower prevailing and future prices could result in lower revenue, earnings and cash flow. Prevailing and future prices for oil, natural gas and NGLs depend on numerous factors beyond our control such as economic conditions, regulatory developments and competition from other energy sources. The energy markets have historically been volatile and recent oil prices have declined from those earlier in 2014 and may fluctuate significantly in the future. Lower prices may reduce the amount of oil, natural gas or NGLs that we can produce economically. Our derivative arrangements serve to mitigate a portion of the effect of this price volatility on our exploration and production cash flows. We will need to incur capital expenditures in 2015 to maintain production levels, develop our reserves and maintain our oilfield equipment; however, such capital expenditures are dependent on availability under debt instruments and proceeds from equity issuances, along with cash flows from operating activities.

Oil, natural gas, and NGL prices have historically been volatile based on supply and demand dynamics. Factors that can affect the demand for our production include domestic and international economic conditions, the market price and demand for energy, the cost to develop oil and natural gas reserves in the United States, along with state and federal regulation. During the fourth quarter of 2014 and continuing into 2015, significant declines in the price of oil, natural gas and NGLs has made it necessary for us to reduce our exploration and development activities, reduce our budget for capital expenditures, and focus on prudent cost reduction efforts.

As an oil, natural gas, and NGL producer, we face the challenge of natural production declines, volatile commodity prices and, as a non-operated working interest owner, operating expenses imposed by our contract operator. As initial reservoir pressures are depleted, oil, natural gas, and NGL production from a given well or formation decreases. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel. Our future drilling plans are dependent on commodity prices. If commodity prices remain low or decline further in 2015, our ability to drill economic wells will be curtailed. Based on current commodity prices, we do not anticipate drilling any new wells until the second half of 2015.

Although we monitor our costs and work with our contract operator to actively manage our expenses, we have seen a significant rise in our lease operating expenses in 2013, which continued in 2014, compared to previous years and expect the higher costs to continue in 2015. In addition, we are currently engaged in litigation with our contract operator and its affiliates, which has affected our exploration and production related cash flow. See “Note 15 - Commitments and Contingencies” to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for additional discussion of this litigation. Based on expected lower commodity prices, higher production costs and less drilling activity, we estimate revenue, operating income and cash flow from operations for our exploration and production business will decline. As such, results for the year ended December 31, 2014 are not indicative of the results that can be expected for the year ending December 31, 2015. In an effort to minimize the impact of anticipated reductions in cash flows from operations, management has significantly reduced its 2015 capital expenditures for exploration and production activities with minimal maintenance activities planned for existing wells and limited drilling activity. As noted above, drilling activity in 2015, which is not anticipated until the second half of 2015, is entirely dependent on commodity prices in the second half of 2015. Although we hold a non-operator working interest in our oil and natural gas properties, we can elect to not participate in drilling new wells proposed by our contract operator. The penalty for not participating varies by area, but is generally a loss in our ability to participate in offset drilling locations drilled in the future. Typically, when we elect to not participate or recommend to defer maintenance activities we believe are not economically beneficial, our contract operator terminates the drilling proposal or delays maintenance activity.

For purposes of determining the present value of estimated future cash inflows from proved oil, natural gas and NGL reserves and calculating our full cost ceiling limitation, we use 12-month average oil, natural gas, and NGL prices for the most recent 12 months as of the balance sheet date and adjusted for basis or location differential, held constant over the life of the reserves. Continued low levels or further declines in oil, natural gas and NGL prices are expected to result in impairments to our full cost pool in multiple quarters in 2015. Additionally, as a non-operator of our properties, we cannot control the costs our contract operator may incur and pass along to us. Higher production costs could result in a reduction to how much we are able to economically

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produce and to our reserves becoming uneconomic, which could result in an impairment of our full cost pool. Based on lower commodity prices, we anticipate an impairment of our oil and natural gas properties during multiple quarters in 2015. The amount of any such impairments is contingent upon many factors such as the price of oil, natural gas and NGLs for the remainder of 2015, increases or decreases in our reserve base, and changes in estimated costs and expenses, which could increase, decrease or eliminate the need for such impairments.

Our credit facility is limited to a borrowing base amount determined by the lenders at their sole discretion, based on their valuation of our proved reserves and their other internal criteria. Based on our reserve estimates and using forward commodity prices, we anticipate a reduction to our borrowing base on our credit facility at the redetermination in April 2015. The precise amount of the reduction is not known at this time but the decrease could range from approximately $20 million to $30 million. Under the credit agreement, we would have approximately three months from the date of notification of a borrowing base reduction to pay any amounts outstanding in excess of the new borrowing base. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with our current ratio covenant in certain future periods. We expect to successfully execute certain contemplated transactions discussed below under "Corporate" to enable us to reduce the credit facility borrowings and comply with this covenant during 2015.

Oilfield Services. As an oilfield services provider of wellsite services during the drilling and completion stages of a well, our business depends substantially on the capital spending programs of our customers. Revenue from our oilfield services segment is generated by providing services to oil and natural gas exploration and production companies located in the Mid-Continent region (Oklahoma, Kansas and the Texas Panhandle), the Permian Basin region (Texas and New Mexico), the Eagle Ford shale region in South Texas, and the Marcellus and Utica shale regions (Pennsylvania, Ohio and West Virginia). Demand for our services is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the areas in which we operate, which in turn is affected by current and expected levels of oil, natural gas, and NGL prices. Due to the decline in oil, natural gas, and NGL prices noted in the fourth quarter of 2014 and continuing into 2015, a trend of decreased drilling activity and planned capital expenditures by our exploration and production customers is developing. Additionally, our customers are allocating drilling resources away from certain less-profitable basins to those basins with better economics. We believe drilling activity will continue to be curtailed until oil prices improve. As a result of the recent decline in commodity prices, the market for oilfield services has experienced downward pricing pressure, which has caused us to offer reduced rates for our services. In an effort to retain our customer base and maintain our market share, we are working with our customers to provide competitive rates for our services until commodity prices improve to more favorable levels. We expect that these competitive rates coupled with our strong safety record and existing customer relationships will provide growth opportunities in the areas we provide services.

A decrease in the demand for our oilfield services coupled with our offering of pricing discounts on our services will result in lower revenues and cash flows from operations on our oilfield services business. We have implemented cost cutting efforts in order to address the impact of anticipated reductions in revenue and cash flows from operations. Such cost cutting efforts include seeking discounts from our vendors, reductions to compensation and reductions to capital expenditures. To the extent cost cutting efforts are not fully realized, the profit on our oilfield services could decline. Maintenance capital expenditures for 2015 are expected to be lower than in 2014, and any growth capital expenditures in 2015 will be completely discretionary and based on our customers' drilling activity levels.

If market conditions decline and a triggering event is deemed to have occurred for purposes of evaluating goodwill or our intangible assets of our oilfield services segment, then we could have an additional impairment to one or more of these assets.

Corporate. We expect to utilize various other financing sources, including additional credit facilities, in order to fund our capital budget, pay distributions to our unitholders and address other liquidity needs, including repayment of current debt obligations, payment of the cash portion of contingent consideration and payment of a portion of the outstanding balance under our credit facility. In addition to the items noted above, we have taken additional steps to address potential shortfalls in cash flow from operations necessary to fund our investing and financing activities. We reduced the quarterly distribution paid in February to $0.20 per unit or $0.80 per unit on an annual basis. This new distribution rate takes into consideration current commodity and financial market conditions and helps to preserve our liquidity. We refinanced our EFS term loan to extend the maturity date from June 2015 to March 2018, which reduced our monthly debt payments. We also extended the date on which the cash portion of the contingent consideration is due to the former owners of EFS and RPS from May 2015 to May 2016.

We are taking additional measures as the above discussed steps may not be sufficient to address our cash flow requirements. We plan to undertake some or all of the following between now and the date on which we would be required to repay any amounts outstanding on our credit facility due to a reduction in the borrowing base:

•sell common units through our existing EDA;

•pursue additional financing, including a second lien loan;

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•monetize our derivative portfolio;

•explore private markets for capital opportunities;

•maintain reduced distributions to our unitholders for additional quarters; and


•	work with the lead bank in the lending group for our credit facility to extend the period to repay any excess amounts outstanding on our credit facility due to a reduction in our borrowing base.

Our ability to access the capital markets or obtain financing at competitive rates is dependent upon various factors including prevailing market conditions and our financial condition. Additionally, due to declines in oil, natural gas, and NGL prices during the end of 2014 and continuing in 2015, access to capital markets may be limited or costs associated with issuing debt may be higher due to increased interest rates, and may affect our ability to access these markets. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition. Additionally, the issuance of common units, whether through equity offerings or to settle our contingent consideration obligations, will result in a higher number of units for which we will pay distributions.

We expect a combination of the actions noted above will be sufficient to enable us to meet our cash flow needs for 2015. However, if we are unsuccessful or market environments are worse than expected, we may be unable to obtain the necessary cash flow needed to meet our obligations, including to pay amounts due on our credit facility or other debt.

Results by Segment

The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, as well as well testing and flowback services. Our oilfield services segment is the aggregation of multiple operating segments that meet the criteria for aggregation due to the economic similarities as well as the similarities in the nature of the services provided, customers served and industry regulations monitored.

Management relies on certain financial and operational metrics to analyze our performance. These metrics are key factors in assessing our operating results and profitability and include (i) revenues, (ii) operating expenses, (iii) gross margin, (iv) Adjusted EBITDA and (v) distributable cash flow.

To evaluate the performance of the Partnership’s business segments, management uses the excess of revenue over direct operating expenses or segment margin. Results of these measurements provide important information to management about the activity, profitability and contributions of the Partnership's business segments. The results of the Partnership's business segments for the years ended December 31, 2014, 2013 and 2012 are discussed below.

Exploration and Production Segment

The Partnership generates a portion of its consolidated revenues and cash flow from the production and sale of oil, natural gas and NGLs. The exploration and production segment’s revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs, our reserves and our future drilling plans. The primary factors affecting the financial results of our exploration and production segment are the prices we receive for our oil, natural gas and NGL production, the quantity of oil, natural gas and NGLs we produce, the costs incurred on our production and changes in the fair value of our commodity derivative contracts. Prices for oil, natural gas and NGLs fluctuate widely and are difficult to predict. Additionally, we have a non-operator position in our oil and natural gas properties, which limits the control we have over certain costs incurred to produce oil, natural gas and NGLs. Our contract operator is a related party. See “Note 11 - Related Party Transactions” to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for additional discussion.

The exploration and production segment's general and administrative expenses include certain costs of our corporate administrative functions and changes in the fair value of contingent consideration obligations related to all acquisitions.

In order to reduce the Partnership’s exposure to price fluctuations, we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in Item 7A "Quantitative and Qualitative Disclosures About Market Risk."

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Set forth in the table below is financial, production and pricing information for our exploration and production segment for the years ended December 31, 2014, 2013 and 2012. For periods prior to the completion of our initial public offering in February 2013, the data below reflects results attributable to the IPO Properties. For periods following the completion of our initial public offering, the data below reflects results attributable to the IPO Properties for the entire period, and properties subsequently acquired from the closing date of their respective acquisition forward.



	Year Ended December 31,
	2014			2013			2012
Results (in thousands):
Oil sales	$	14,906		$	8,090		$	5,570
Natural gas sales	15,534			10,000			6,030
NGL sales	31,048			28,847			23,996
Total revenues	61,488			46,937			35,596
Production expenses	18,617			12,631			6,217
Production taxes	2,833			2,669			1,144
Segment margin	40,038			31,637			28,235
Depreciation, depletion, and accretion	25,113			16,799			14,525
General and administrative	11,051			13,787			12,660
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
Operating income	$	12,905		$	2,651		$	1,050

Production volumes:
Oil (Bbls)	163,338			84,273			61,010
Natural gas (Mcf)	3,673,836			2,764,336			2,278,342
NGLs (Bbls)	885,117			790,234			711,195
Total production volumes (Boe)	1,660,761			1,335,230			1,151,929
Average daily production volumes (Boe)	4,550			3,658			3,156

Average price:
Oil (per Bbl)	$	91.26		$	96.00		$	91.30
Natural gas (per Mcf)	4.23			3.62			2.65
NGL (per Bbl)	35.08			36.50			33.74
Total, excluding derivatives (per Boe)	37.02			35.15			30.90
Cash (paid) received on derivative settlements (per Boe)	(1.07		)	(1.44		)	5.20
Total, including derivatives (per Boe)	$	35.95		$	33.71		$	36.10

Average production costs (per Boe)(1)	$	11.21		$	9.46		$	5.40

_______________


(1)	Includes lease operating expense and workover expense.

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

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.

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

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.

Revenue

Revenues from our exploration and production segment were $61.5 million for the year ended December 31, 2014, an increase of $14.6 million, or 31.0%, from 2013, as a result of higher production and higher prices received on our natural gas production. Production increased 325.5 MBoe, or 24.4%, in 2014 compared to 2013. While average prices received on oil and NGL production were lower in 2014, average prices on natural gas production were higher resulting in a higher average price per Boe received on our combined production of $1.87, or 5.3%, in the year ended December 31, 2014.

Revenues were $46.9 million for the year ended December 31, 2013, an increase of $11.3 million, or 31.9%, compared to the year ended December 31, 2012. The increase in revenue during the year ended December 31, 2013 was due to increased production and higher prices received on our production. Our combined production increased 183.3 MBoe, or 15.9%, and the average price per Boe received on our combined production increased $4.25, or 13.8%, in 2013 compared to 2012.

The increase in production volumes during the years ended December 31, 2014 and 2013 was a result of production from oil and natural gas properties acquired during 2013 and 2014.

Operating Expenses

Production expenses. Production expense includes costs associated with exploration and production activities, including lease operating expense and treating costs. 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.

Production expenses increased $6.0 million, or 47.4%, which is an increase of $1.75 per Boe, for the year ended December 31, 2014 from 2013. Production expenses increased $6.4 million, or 103.2%, for the year ended December 31, 2013 compared to 2012, which results in an increase of $4.06 per Boe for 2013. The increase in production expenses for the years ended December 31, 2014 and 2013 was partially due to production costs from oil and natural gas properties acquired during 2013 and 2014. The acquisitions of properties in the Southern Dome field, which produces more oil than our other fields, contributed to higher production costs per Boe as oil production has higher production costs compared to production costs on natural gas volumes. In addition, we incurred higher operator fees and costs on our production in 2013 and 2014. As a non-operating working interest owner, we are subject to costs and fees as incurred and determined by the contract operator. We monitor such costs and are working with our contract operator and other working interest owners to ensure costs are reasonable.

Production 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.

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Likewise, in general, as prices and volumes decrease, our production taxes decrease. Production taxes increased $0.2 million, or 6.1%, and $1.5 million, or 133.3%, in the years ended December 31, 2014 and 2013, respectively, from the same periods in 2013 and 2012. The increase in production taxes is due to the increase in volumes produced and prices received on our production in 2014 and 2013. A portion of our wells benefit from certain tax credits relating to the drilling of horizontal wells. Due to these credits and the types of wells drilled, our production taxes will fluctuate from period to period in addition to variances from changes in prices and production.

Depreciation, depletion, and accretion. Depreciation, depletion, and accretion expense increased $8.3 million, or 49.5%, for the year ended December 31, 2014 from the comparable period in 2013. The increase is due to the increase in combined production of 24.4% during 2014 and an increase of $2.50 per Boe in the average depletion rate due to a decline in our reserve base.

Depreciation, depletion and accretion expense increased $2.3 million, or 15.7% for the year ended December 31, 2013 from the comparable period in 2012. In historical periods, prior to our IPO, depreciation, depletion and accretion expense reflects an allocation of NSEC’s depreciation and depletion based on the proportion of historical production attributable to the IPO Properties. For the period February 13, 2013 through December 31, 2013, depreciation and depletion were computed by using specific production, reserves and future development costs directly attributable to the Partnership’s properties.

General and administrative. In 2014, general and administrative expense decreased $2.7 million, or 19.8%, from 2013 primarily due to lower equity-based compensation expense in 2014 and the elimination of the NSEC quarterly management and administrative services fees paid in 2013. Partially offsetting the decrease are additional corporate costs related to salary and benefits due to additional corporate-level employees and higher acquisition related costs in 2014. For the year ended December 31, 2014, general and administrative expenses included $0.6 million for equity-based compensation and $3.3 million for acquisition-related costs. General and administrative expense for the year ended December 31, 2013, included equity-based compensation of $7.8 million, acquisition expenses of $2.1 million primarily for the MCE Acquisition and approximately $2.4 million of fees paid to NSEC for administrative services in 2013.

General and administrative expense in 2013 increased $1.1 million, or 8.9%, as compared to 2012 primarily due to increased acquisition-related costs and our participation in an omnibus agreement, whereby we paid NSEC a quarterly fee of approximately $0.7 million for the provision of management and administrative services. For periods prior to the IPO, the general and administrative expenses reflect an allocation of NSEC’s general and administrative expenses based on the proportion of historical production attributable to the IPO Properties.

Change in fair value of contingent consideration. The gain on the change in fair value of contingent consideration increased $7.4 million in 2014 as compared to 2013. For the year ended December 31, 2014, the gain is primarily attributable to the contingent consideration for the acquisitions of MCE and MCCS being reduced to zero because current projections for the first quarter of 2015 estimate that the earn out targets would not be met. Also contributing to the gain is an adjustment to the contingent consideration for the acquisitions of EFS and RPS based on actual results for the earn out period. For the year ended December 31, 2013, the gain is attributable to a decrease in fair value of the contingent consideration for the acquisition of oil and natural gas properties in the Southern Dome field in October 2013. See "Note 2 - Acquisitions" and "Note 3 - Contingent Consideration" to the Partnership’s consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for additional discussion related to these acquisitions and related contingent considerations.

Oilfield Services Segment

Our Oilfield Services segment is focused on providing services to companies engaged in the production of oil and natural gas from United States onshore unconventional reservoirs. We provide essential wellsite services during the drilling and completion stages of a well, including blowout prevention, surface valve and flowback services for both horizontal wells and vertical wells. We offer our services in several oil and natural gas production regions in North America, including the Mid-Continent region (Oklahoma, Kansas and the Texas Panhandle), the Permian Basin region (Texas and New Mexico), the Eagle Ford shale region in South Texas, and the Marcellus and Utica shale regions (Pennsylvania, Ohio and West Virginia). The primary factors affecting the results of the oilfield services segment are the rates received and the amount of oilfield services provided.

The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. In June 2014, we acquired oilfield services companies that specialize in providing well testing and flowback services to the oil and natural gas industry primarily in Oklahoma, Texas, Pennsylvania and Ohio. As such, information for the 2013 period is not comparable. See "Note 2 - Acquisitions" to the consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for discussion of these acquisitions.

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	Year Ended December 31,
	2014			2013
Results (in thousands):
Oilfield service revenue	$	104,155		$	3,738
Cost of providing oilfield services	60,904			2,040
Total segment margin	43,251			1,698
Depreciation and amortization	29,566			1,966
Impairment of goodwill and other intangible assets	59,000			—
General and administrative	17,620			973
Operating loss	$	(62,935	)	$	(1,241	)

Revenue

Oilfield services revenues, which include revenue from blowout prevention installation, flowback installation and pressure testing services, fluctuate based on drilling activity in the areas in which we operate. Our service revenue is generated based on the type of service we provide at an established rate. The rate used varies depending on the service provided, the specific basin the service is dispatched from and market conditions.

Revenues from our oilfield services segment were $104.2 million and $3.7 million for the years ended December 31, 2014 and 2013, respectively. The increase in oilfield services revenue is due, in large part to the acquisition of EFS and RPS in June 2014. EFS and RPS contributed revenues, primarily associated with flowback services, of approximately $62.0 million from the acquisition date (June 26, 2014) to December 31, 2014. With the acquisition of EFS and RPS, we added ten yards and field offices (combined) and 95 flowback spreads as of the acquisition date. Also contributing to the increase is a full year of higher revenue from MidCentral Energy Services LLC ("MCES"). During 2014, MCES expanded the services it provides and the areas in which it operates. MCES also added pressure spreads, or needed stock and ancillary equipment necessary to perform pressure control services, which allowed it to provide more services. Specifically, MCES expanded its position in South Texas by using a larger sales force to grow its customer base and providing additional services to its existing customers through strengthened customer relationships as a result of delivering quality service. MCES also expanded its market share in the Mid-Continent region and began providing services in West Texas during 2014.

Operating Expenses

Costs of providing oilfield services. Our oilfield services operating costs consist of direct and indirect costs. Direct costs include field, shop and mechanic’s labor, fuel, maintenance and repairs on revenue producing equipment, and various supplies. Indirect costs consist of administrative expenses including, labor, insurance and selling expenses. The cost of providing oilfield services was $60.9 million and $2.0 million for the years ended December 31, 2014 and 2013, respectively. The increase in costs is due in large part to the acquisition of EFS and RPS in June 2014. EFS and RPS had costs of revenues of approximately $36.7 million from the acquisition date (June 26, 2014) to December 31, 2014. Also contributing to the increase is a full year of costs for MCES. There are additional costs associated with MCES, primarily field labor, due to an increase in services provided, as discussed above, and the addition of field managers to ensure quality and safety standards are maintained on job sites.

Depreciation and amortization. Depreciation and amortization expense of $29.6 million and $2.0 million for the years ended December 31, 2014 and 2013, respectively, primarily represents the amortization of our intangible assets from the acquisitions of MCE, MCCS, EFS and RPS. Amortization expense on intangible assets of customer relationships and non-compete agreements, which were recognized at the time of acquisitions, was $25.0 million for the year ended December 31, 2014 compared to $1.8 million for the same period in 2013. Customer relationships are amortized using an accelerated method over seven years. Non-compete agreements are amortized straight-line over the agreement period or three years. Additionally, EFS and RPS had depreciation of approximately $2.9 million from the acquisition date (June 26, 2014) to December 31, 2014.

Impairment of goodwill and other intangible assets. In the fourth quarter of 2014, we recorded impairment of $59.0 million on goodwill and our customer relationship intangible assets. The impairment of goodwill was a result of the carrying value of our reporting units exceeding the estimated fair value of our reporting units. The impairment of our customer relationship intangible assets was the result of the carrying value exceeding the fair value of the asset group. See "Note 8 - Goodwill and Intangible Assets"

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to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for additional discussion of impairment assessments performed.

General and administrative. General and administrative expenses, which include sales, professional fees, office expenses, and equity compensation, were $17.6 million and $1.0 million for the years ended December 31, 2014 and 2013, respectively. The increase in general and administrative expenses is primarily due to the acquisition of EFS and RPS in June 2014. EFS and RPS had general and administrative expenses of approximately $10.3 million from the acquisition date (June 26, 2014) to December 31, 2014. Additionally, the year ended December 31, 2014 includes a full year of general and administrative expenses for MCES.

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

Results of Operations

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



	Year Ended December 31,
	2014			2013			2012
	(in thousands)
Operating (loss) income	$	(50,030	)	$	1,410		$	1,050
Other income (expense):
Interest expense	(5,041		)	(4,078		)	(3,202		)
Gain (loss) on derivative contracts, net	10,707			(5,548		)	7,057
Gain on investment in acquired business	2,298			22,709			—
Other (loss) income	(9		)	3			—
(Loss) income before income taxes	(42,075		)	14,496			4,905
Income tax benefit (expense)	—			12,126			(1,796		)
Net (loss) income	$	(42,075	)	$	26,622		$	3,109

Other Income/Expense

Interest expense. Interest expense increased $1.0 million or 23.6% for the year ended December 31, 2014. The increase was due to higher average debt balances in 2014 compared to 2013, primarily as a result of additional borrowings under our credit facility to fund acquisitions and corporate growth as well as the write off of $0.2 million of loan fees associated with the decrease in the borrowing base on our credit facility during the fourth quarter of 2014. This increase was partially offset by a write off of $1.4 million of loan fees associated with extinguishing debt in 2013.

Interest expense increased $0.9 million, or 27%, to $4.1 million in 2013 from $3.2 million in 2012. The increase was primarily due to increased borrowings from our credit facility and write-off of loan fees in 2013.

Gain (loss) on derivatives, net. Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded each quarter as a component of operating expenses. In general, cash is received on settlement of contracts due to lower oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps, and cash is paid on settlement of contracts due to higher oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps.

Gain on derivative contracts was $10.7 million in 2014 compared to loss on derivative contracts of $5.5 million in 2013. The gain on derivative contracts in 2014 was primarily due to lower oil, natural gas, and NGL prices at December 31, 2014 compared to the contract price or prices at December 31, 2013.

Loss on derivative contracts was $5.5 million in 2013 compared to gain on derivative contracts of $7.1 million in 2012. The loss is primarily the result of higher natural gas and NGL settlement and futures prices in the 2013 period compared with the 2012 period. In July 2012, we liquidated all of our oil, natural gas and NGL swap and collar derivative positions and realized net proceeds of approximately $4.9 million. Subsequently in July 2012, we entered into new fixed price swap derivative contracts for these commodities at approximately 50% of the volumes previously hedged at then current prices.

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Gain on investment in acquired business. As discussed in "Note 2 - Acquisitions" to the consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report, the Partnership initially recorded the 50% equity interest in MCCS acquired from Mr. Kos at his equity method carrying basis, which was $0.1 million as of June 26, 2014. The Partnership remeasured the 50% interest to determine the acquisition-date fair value and recognized a corresponding gain of $2.3 million on investment in acquired business for the year ended December 31, 2014.

During the year ended December 31, 2013, the Partnership initially recorded the 36% equity interest in MCE acquired from Mr. Kos at his equity method carrying basis, which was $1.8 million as of November 12, 2013. The Partnership remeasured the 36% interest to determine the acquisition-date fair value and recognized a corresponding gain of $22.7 million on investment in acquired business.

Income taxes. Income tax benefit was $12.1 million in 2013 compared to an expense of $1.8 million in 2012. The IPO Properties were owned by a tax paying entity in 2012 and incurred deferred income taxes based on the differences in book and tax basis of the properties at that date. After completion of our IPO in February 2013, all of our properties are now owned by a nontaxable entity, and we have recognized a tax benefit due to the change in tax status.

Non-GAAP Financial Measures

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

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A reconciliation of Adjusted EBITDA to net (loss) income for the year ended December 31, 2014, 2013 and 2012 is provided below:



	Year Ended December 31,
	2014			2013			2012
	(in thousands)
Reconciliation of adjusted EBITDA to net (loss) income:
Net (loss) income attributable to New Source Energy Partners L.P.	$	(42,317	)	$	26,622		$	3,109
Interest expense	5,041			4,078			3,202
Franchise tax expense (income tax benefit)	5			(12,126		)	1,796
Depreciation, depletion and amortization	54,352			18,556			14,409
Accretion expense	327			209			116
Impairment	59,000			—			—
Non-cash compensation expense	3,233			7,839			8,204
Acquisition and transaction fees	3,659			2,078			—
Other non-cash expense	585			—			—
Gain on acquisition of business	(2,298		)	(22,709		)	—
(Gain) loss on derivative contracts, net	(10,707		)	5,548			(7,057		)
Cash (paid) received on settlement of derivative contracts	(1,773		)	(1,929		)	5,987
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
Adjusted EBITDA	$	60,076		$	26,566		$	29,766

A reconciliation of Adjusted EBITDA to net income (loss) for our exploration and production and oilfield services segments for the year ended December 31, 2014 is provided below:



	Year Ended December 31, 2014
	Year Ended December 31, 2014
	E&P			OFS
Reconciliation of adjusted EBITDA to net income (loss):	(in thousands)
Net income (loss) attributable to New Source Energy Partners L.P.	$	21,942		$	(64,259	)
Interest expense	3,726			1,315
Franchise tax expense	—			5
Depreciation, depletion and amortization	24,786			29,566
Accretion expense	327			—
Impairment	—			59,000
Non-cash compensation expense	644			2,589
Acquisition and transaction fees	3,340			319
Other non-cash expense	—			585
Gain on acquisition of business	(2,298		)	—
Gain on derivative contracts, net	(10,707		)	—
Cash paid on settlement of derivative contracts	(1,773		)	—
Change in fair value of contingent consideration	(9,031		)	—
Adjusted EBITDA	$	30,956		$	29,120

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Liquidity and Capital Resources

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under existing debt instruments by our oilfield services subsidiaries and the issuance of equity securities in the capital markets. To date, our primary uses of capital have been for the acquisition and development of oil and natural gas properties, the acquisition of our oilfield services business through the MCE Acquisition and the Services Acquisition, distributions to our unitholders and working capital needs.

Our ability to finance our operations, including funding capital expenditures and acquisitions, to meet our indebtedness obligations, and to pay distributions to our unitholders depends on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices, capital expenditures of our oilfield services customers and our ongoing efforts to manage production volumes, operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors.

Refer to "2015 Outlook" above for a discussion of our 2015 outlook, including discussion of liquidity and capital resources.

Capital Requirements

Because we distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production. As a result, we may not grow as quickly as other oil and natural gas entities or at all. We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including borrowings under debt instruments and the issuance of equity securities, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions.

Distributions

Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and the general partner. See Item 5 "Market for Registrant's Common Equity, Related Unitholder Matters and issue Purchases of Equity Securities" of this report for additional information regarding the partnership agreement. Our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions for certain purposes, including in circumstances where our general partner believes that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. Beginning with the distribution paid in February 2015, our general partner decided a reduction to the distribution amount was necessary because of the current pricing environment for oil, natural gas, and NGL and the Partnership's common unit price relative to the previous distribution levels. Accordingly, the distribution was reduced to $0.20 per unit.

Distributions are declared and distributed within 45 days following the end of each quarter. Quarterly distributions to unitholders of record, including holders of common, subordinated and general partner units applicable to the years ended December 31, 2014 and 2013, are shown in the following table (in thousands, except per unit amounts):

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Distributions	Payable Date	Distribution per Unit		Common Units		Subordinated Units		General Partner Units		Total
2014
First Quarter	May 15, 2014	$	0.580	$	7,852	$	1,279	$	90	$	9,221
Second Quarter	August 15, 2014	$	0.585	$	9,025	$	1,290	$	91	$	10,406
Third Quarter	November 14, 2014	$	0.585	$	9,454	$	1,290	$	91	$	10,835
Fourth Quarter (3)	February 13, 2015	$	0.200	$	3,281	$	—	$	31	$	3,312

2013
First Quarter (1)	May 15, 2013	$	0.274	$	1,857	$	605	$	43	$	2,505
Second Quarter	August 15, 2013	$	0.550	$	3,725	$	1,213	$	85	$	5,023
Third Quarter	November 15, 2013	$	0.575	$	3,895	$	1,268	$	89	$	5,252
Fourth Quarter (2)	February 14, 2014	$	0.575	$	4,681	$	1,268	$	89	$	6,038

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(1)	Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit.


(2)	Distributions were not paid on the 1,947,033 common units issued in conjunction with the MCE Acquisition pursuant to an arrangement with the sellers to forgo their rights to distributions for the fourth quarter of 2013 on these units.

(3)

Because the declared common unit distribution is below the Partnership’s Minimum Quarterly Distribution of $0.525 per unit, the Partnership’s subordinated units were not entitled to receive distributions. Under the terms of the partnership agreement, the subordinated units are entitled to distributions once the common unit distribution meets or exceeds the Minimum Quarterly Distribution and all common unit arrearages have been satisfied.

Cash Flows

Cash Flows from Operating Activities

Cash provided by operating activities is impacted by the prices we are able to charge for our oilfield services, prices received for oil, natural gas, and NGL sales and levels of production. Production volumes in the future will be largely dependent upon the amount of and results of future capital expenditures. Future levels of capital expenditures may vary due to many factors, including drilling results, commodity prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.

Net cash provided by operating activities was approximately $44.9 million and $18.4 million for the years ended December 31, 2014 and 2013, respectively. The increase in cash provided by operating activities is primarily a result of our acquisitions of oil and natural gas properties in 2013 and 2014, which increased the Partnership's revenue from oil, natural gas, and NGL production, as well as our acquisitions of EFS and RPS in 2014, which resulted in increased revenue attributable to our oilfield services.

Net cash provided by operating activities was approximately $18.4 million and $27.8 million for the years ended December 31, 2013 and 2012, respectively. The decrease in net cash provided by operating activities during 2013 as compared to 2012 is primarily due to an increased delay in collections of receivables, an increase in the length of our drilling cycles, and increases in production costs and general and administrative expenses.

Cash Flows from Investing Activities

Cash flows used in investing activities are related to acquisitions and capital expenditures for the development of our oil and natural gas properties and equipment for our oilfield services business. Net cash used in investing activities was approximately $99.7 million and $51.0 million for the years ended December 31, 2014 and 2013, respectively. The increase is primarily attributable to the Services Acquisition and the CEU Acquisition during 2014. Our acquisitions are described further in "Note 2 - Acquisitions" in Item 8 "Financial Statements and Supplementary Data” of this report.

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Net cash used in investing activities was approximately $51.0 million and $12.2 million for the years ended December 31, 2013 and 2012, respectively. The increase in cash flows used in investing activities is primarily due to the acquisitions of oil and natural gas properties as well as the acquisition of MCE in 2013.

Cash Flows from Financing Activities

Financing cash flows are primarily related to debt and equity financing of property development and acquisitions and working capital. Net cash provided by financing activities was approximately $53.0 million and $40.0 million for the years ended December 31, 2014 and 2013, respectively. The increase in net cash provided by financing activities is primarily due to the equity offerings in April and October of 2014. Additionally, there was a payment on the subordinated note payable of $25.0 million in 2013.

Net cash provided by (used in) financing activities was approximately $40.0 million and $(15.6) million for the years ended December 31, 2013 and 2012, respectively. The increase in net cash provided by financing activities is primarily due to proceeds from the sale of our common units in our IPO and proceeds from borrowings on our revolving credit facility.

Working Capital

Working capital is the difference in current assets and current liabilities and is an indicator of liquidity and the potential need for short-term funding. The changes in our working capital requirements are driven generally by changes in accounts receivable, accounts payable, commodity prices, debt repayments and contingent consideration. Our working capital was $4.0 million and $3.7 million at December 31, 2014 and December 31, 2013, respectively. The former owners of EFS and RPS are entitled to receive additional consideration in the form of common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). Excluding the liability related to this contingent consideration, which is to be paid in common units, working capital at December 31, 2014 would have been $15.6 million. The increase in working capital in 2014 is primarily due to an increase of approximately $8.1 million in the value of our current derivative contracts.

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage) and are estimated as the amount of capital expenditures necessary to maintain the revenue generating capabilities of our assets at current levels over the long term. With respect to our oil and natural gas operations, estimated maintenance capital expenditures represent the average cost to replace a barrel of oil equivalent, using the historical average finding and development costs over the preceding five-year period and the actual production volume for such period. However, future finding and development costs could be higher, which could result in drilling opportunities being limited or uneconomic. With respect to our oilfield services operations, estimated maintenance capital expenditures represent the estimated replacement costs for current equipment whose useful lives are scheduled to be completed during the given year. For the year ended December 31, 2014, our total maintenance capital expenditures were approximately $18.2 million.

Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The purpose of growth capital is primarily to acquire producing assets that will increase our distributions per unit and secondarily to increase the rate of development and production of our existing oil and natural gas properties and increase the size and scope of our oilfield services business in a manner that is expected to be accretive to our unitholders. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. We expect to primarily rely upon external financing sources, including borrowings under debt instruments, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions.

Because our future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production and services, there can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our current production levels. Our drilling activity for 2015 is limited and dependent on commodity prices. If we do not pursue drilling activities, our reserves and production will decrease over time and not be replaced. We may increase or decrease planned capital expenditures, including acquisitions, depending on oil, natural gas and NGL prices, demand for our oilfield services and prices we can charge for such services, and the availability of capital through the issuance of additional common units or long-term debt. A decrease in capital expenditures could limit our ability to increase or replace our reserves, which could reduce our production volumes over time, and impact our ability to purchase additional equipment for our oilfield services business.

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Credit Facility

Our credit facility is a four-year, senior secured credit facility. The amount we may borrow under the credit facility is limited to a 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 at 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 oil, natural gas, and NGL reserves, which will take into account the prevailing oil, natural gas, and NGL prices at such time, as adjusted for market differentials and the impact of our derivative contracts.

Declines in commodity prices, increases in production costs and other factors that impact our reserves occurred in the fourth quarter of 2014 in a redetermination that lowered our borrowing base from $102.5 million to $90.0 million. Such factors could result in a lowered borrowing base in the future, which could require us to repay any indebtedness in excess of the borrowing base, unless we are able 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 credit facility. Additionally, if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we are prohibited from paying distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our credit facility.

Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) the London Interbank Offered Rate ("LIBOR") plus 1.0%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans at shorter intervals. At December 31, 2014 and 2013, the average annual interest rate on borrowings outstanding under the credit facility was 3.44% and 3.25%, respectively. At December 31, 2014, the borrowing base under the credit facility was $90.0 million with $7.0 million of available borrowing capacity and no available borrowing capacity before restriction on distribution occurs. In January and February 2015, the Partnership repaid $2.0 million in outstanding borrowings under the credit facility, which resulted in $81.0 million outstanding with no restrictions on our ability to pay distributions in February 2015.

As of December 31, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully defined in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. As of December 31, 2014, the Partnership was in compliance with all covenants under the credit facility.

The borrowing base is subject to a number of factors including quantities of proved oil, natural gas and NGL reserves and the bank's price assumptions. Based on our reserve estimates and using forward commodity prices, we anticipate a decrease to our borrowing base of approximately $20 million to $30 million as a result of the redetermination in April 2015. Under the credit agreement, we have approximately three months from the date of notification of a borrowing base reduction to pay any amounts outstanding in excess of the new borrowing base. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with our current ratio covenant in certain future periods. We are currently pursuing financing options available to us and anticipate being able to address these issues and retain liquidity through debt or equity issuances.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to its accounts receivable. Interest only payments are due monthly with the line of credit maturing in May 2015. The line of credit replaced MCES' factoring payable agreement described below. Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at December 31, 2014. The line of credit is secured by accounts receivable, inventory, chattel paper and general intangibles of MCES. Based on the outstanding balance of $3.6 million, there was $0.4 million of available borrowing capacity at December 31, 2014.

As of December 31, 2014, the line of credit contained a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of December 31, 2014, MCE was in compliance with this covenant under the line of credit.

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Notes Payable

The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. These notes range from 12-60 months in duration with maturity dates from August 2015 through April 2018 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. The Partnership had $7.6 million outstanding under the MCES notes payable as of December 31, 2014.

In conjunction with the Services Acquisition, the Partnership assumed the outstanding balances on term loans held by EFS. These term loans had a balance of $12.9 million as of December 31, 2014 and mature on June 26, 2015. The term loans have a variable interest rate based on the Bank 7 Base Rate minus 2.3%, which was 5.5% at December 31, 2014, with a minimum interest rate of 5.5%. Payments of principal and interest are due in monthly installments. The term loans are collateralized by various assets of the parties to the agreement and guaranteed by MCE and former owners of EFS and RPS. The Partnership is required to maintain a reserve bank account into which the lesser of $0.3 million or 100% of excess cash flow (as defined in the loan agreement) shall be deposited quarterly and used to fund an additional annual payment on September 30th of each year during the term of the loans.

The EFS term loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge, make distributions or transfer all or substantially all of its assets; make certain investments; and dispose of assets. Additionally, beginning October 1, 2014, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0 (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $4.0 million, in each case as more fully described in the loan agreement. As of December 31, 2014, EFS and RPS were in compliance with the covenants under the term loan agreement. On March 13, 2015, we re-financed the EFS term loans to extend the maturity date from June 26, 2015 to March 13, 2018, which reduced the monthly payment, the reserve account requirement and the minimum working capital and cash balance covenant requirements. All other covenants and restrictions remained the same.

Factoring Payable

In conjunction with the Services Acquisition, the Partnership assumed the EFS and RPS factoring agreements. Under these factoring agreements, invoices to pre-approved customers are submitted to the bank and the Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Factoring fees, calculated based on three month LIBOR plus 3% (subject to a monthly minimum), are deducted from collected receivables. These factoring fees, along with an annual fee, are included in interest expense in the statement of operations. If a receivable is not collected within 90 days, the receivable is repurchased by the Partnership out of either the Partnership's reserve fund or current advances. The outstanding balance of the factoring payable was $13.2 million as of December 31, 2014.

Equity Offerings

In October 2014, the Partnership and our general partner entered into an EDA with the Sales Agent. Pursuant to the terms of the EDA, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. On October 6, 2014, the Partnership sold 720,000 common units under the EDA for proceeds of approximately $16.2 million, net of offering costs, which included a commission to the Sales Agent of 1.75% on the principal amount of the offering. Proceeds were used to pay down a portion of the Partnership's outstanding debt and for general corporate purposes. No additional sales were made through December 31, 2014.

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Contractual Obligations

A summary of our contractual obligations as of December 31, 2014 is provided in the following table (in thousands).



	Obligations Due in Period
Contractual Obligation	2015		2016		2017		2018		2019		Thereafter		Total
Long-term debt	$	11,825	$	7,185	$	87,809	$	219	$	5	$	—	$	107,043
Interest on long-term debt and credit facility (1)	4,287		3,034		2,912		7		—		—		10,240
Operating leases	1,299		1,126		650		424		312		520		4,331
Total contractual obligations	$	17,411	$	11,345	$	91,371	$	650	$	317	$	520	$	121,614

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(1)

Estimated interest using the actual weighted average interest rate of the Partnership's revolving credit facility of 3.44% and a weighted average interest rate on the MCE debt of 6.43% as of December 31, 2014. The Partnership's revolving credit facility rate is variable and could change in the future; however, we believe this is a reasonable estimate considering recent Federal Reserve interest rate policy.

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, 2014 is $3.7 million.

The former owners of EFS and RPS are entitled to receive additional consideration in the form of cash and common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments. The terms of the contribution agreement provide that the additional consideration is to be paid approximately 50% in cash and approximately 50% in common units, consistent with the initial consideration for the Services Acquisition. The fair value of the contingent consideration was $23.3 million as of December 31, 2014. In March 2015, we entered into an agreement with the former owners that allows for the payment of the cash portion of the contingent consideration to be extended to May 2016. Additionally, a receivable of approximately $1.0 million due from the former owners has been offset against the contingent consideration obligation.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires management to make assumptions, estimates, and judgments that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. Management bases these estimates on historical experience, available information and various other assumptions it believes to be reasonable under the circumstances. Actual results could differ from those estimates. Estimates of oil, natural gas and NGL reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of oil, natural gas, and NGL that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect the Company’s future depletion, depreciation and amortization expenses. Additional significant estimates include but are not limited to the allowance for doubtful accounts, depreciation and amortization of property and equipment, and future cash flows and fair values used to assess recoverability and impairment of long-lived assets. The accounting policies discussed below reflect our more significant estimates and assumptions used in the preparation of our financial statements. Our critical accounting policies and additional information on significant estimates used by the Partnership are discussed below. See "Note 1 - Summary of Significant Accounting Policies" to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for additional discussion of the Company’s significant accounting policies.

Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to its expected oil, natural gas, and NGL production, we enter into oil, natural gas, and NGL derivative contracts. We recognize our derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. We have elected not to designate price risk management activities as

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accounting hedges under applicable accounting guidance, and, accordingly, account for our commodity derivative contracts at fair value with changes in fair value reported currently in earnings. We net derivative assets and liabilities whenever we have a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of our derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statement of cash flows.

Fair values of commodity derivative financial instruments are determined primarily by using discounted cash flow calculations or option pricing models, and are based upon inputs that are either readily available in the public market, such as oil, natural gas, and NGL futures prices, volatility factors, interest rates and discount rates, or can be corroborated from active markets. Estimates of future prices are based upon published forward commodity price curves for oil, natural gas, and NGL instruments. Valuations also incorporate adjustments for our nonperformance risk or that of out counterparties, as applicable.

Proved Reserves. Approximately 100% of our reserves were estimated by independent petroleum engineers for the year ended December 31, 2014. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond our control. Estimating reserves is a complex process and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2014, 2013 and 2012, we revised our proved reserves from prior years’ reports by approximately (5,511.4) MBoe, (591.2) MBoe and (195.9) MBoe, respectively, due to market prices during or at the end of the applicable period, or production performance indicating more (or less) reserves in place, larger (or smaller) reservoir size than initially estimated and, in 2014, the reclassification of certain proved undeveloped reserves to probable reserves because our expected drilling plan has been curtailed as a result of low commodity prices and rising costs to drill wells. Estimates of proved reserves are key components of our most significant financial estimates used to determine depreciation and depletion on oil and natural gas properties and our full cost ceiling limitation. Future revisions to estimates of proved reserves may be material and could materially affect our future depreciation and depletion expenses.

Method of Accounting for oil and natural gas properties. Our business is subject to accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil, natural gas, and NGL business activities: the successful efforts method and the full cost method. We use the full cost method to account for our oil and natural gas properties. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Exploration and development costs include dry well costs, geological and geophysical costs, direct overhead related to exploration and development activities and other costs incurred for the purpose of finding oil, natural gas and NGL reserves. Amortization of oil and natural gas properties is calculated using the unit-of-production method based on estimated proved oil, natural gas and NGL reserves. Sales and abandonments of oil and natural gas properties being amortized are accounted for as adjustments to the full cost pool, with no gain or loss recognized, unless the adjustments would significantly alter the relationship between capitalized costs and proved oil, natural gas and NGL reserves. A significant alteration would not ordinarily be expected to occur upon the sale of reserves involving less than 25% of the proved reserve quantities of a cost center. 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 and impairment of oil and natural gas properties are generally calculated on a well by well, lease or field basis versus the aggregated “full cost” pool basis. Additionally, gain or loss is generally recognized on all 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, natural gas, and NGL depreciation and depletion rate, and we will not have exploration expenses that successful efforts companies frequently have.

Impairment of oil and natural gas properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation. The capitalized cost of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes, may not exceed an amount equal to the present value of future net revenues from proved oil, natural gas and NGL reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less related tax effects (the “ceiling limitation”). We calculate our full cost ceiling limitation using the 12-month average oil, natural gas, and NGL prices for the most recent 12 months as of the balance sheet date and adjusted for basis or location differential, held constant over the life of the reserves. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down is not reversible at a later date. There were no full cost ceiling impairments recorded during the years ended December 31, 2014, 2013 or 2012.

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Allowance for Doubtful Accounts. Accounts receivable are reviewed and an estimate for losses is provided through an allowance for doubtful accounts when deemed appropriate. In evaluating the level of established reserves, we make judgments regarding our customers’ ability to make required payments, economic events and other factors. As the financial condition of customers changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event we were to determine that a customer may not be able to make required payments, we would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made that they will not be collected.

Property and Equipment. Property and equipment includes facilities and equipment used in our oilfield services operations. Depreciation of such property and equipment is computed using the straight-line method over the estimated useful life of the assets, which range from 3 to 10 years. In order to depreciate our property and equipment, we estimate useful lives and salvage values of these items. Our estimates may be affected by such factors as changing market conditions, technological advances or changes in regulations governing the industry.

Impairment of Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset or asset group to the forecast of undiscounted estimated future net cash flows expected to be generated by the asset or asset group. If such assets are considered to be impaired, the impairment to be recognized is the amount by which the carrying amount of the asset or asset group exceeds our forecast of the discounted estimated future net operating cash flows directly related to the asset or asset group including disposal value, if any. We make estimates and judgments about future undiscounted cash flows and fair values. Although our cash flow forecasts are based on assumptions that are consistent with our plans, there is a significant degree of judgment involved in determining the cash flows attributable to a long-lived asset over its estimated remaining useful life. Our estimates of anticipated cash flows could be reduced significantly in the future and as a result, the carrying amounts of our long-lived assets could be subject to impairment charges in the future.

Goodwill, Intangible Assets and Amortization. Goodwill is not amortized, but tested for impairment annually or more frequently if circumstances indicate that impairment may exist. Intangible assets with definite useful lives are amortized either on a straight-line basis over the asset’s estimated useful life or on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized. The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units and a comparison of the estimated fair values of the reporting units to their carrying amounts. Our estimates of fair value involve the use of different valuation techniques, including a combination of the income and market approach. Determining the fair value of a reporting unit is a matter of judgment and often involves the use of significant estimates and assumptions. If the fair value of the reporting unit is less than its carrying value, an impairment loss is recorded to the extent that the implied fair value of the reporting unit’s goodwill is less than its carrying value. Our assessment included a review of changes in key company financial metrics and other measures that are important to the company's success, including demand for our products and services, maintenance of customers and cost of producing our product. Our estimates of the fair value of the reporting units represent our best estimates based on industry trends and reference to market transactions. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Significant changes to these assumptions could require an additional provision for impairment in a future period. Refer to "Impairment of Long-Lived Assets" above for discussion of impairment assessments for intangible assets with definite lives. See "Note 8 - Goodwill and Intangible Assets" to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.

Asset Retirement Obligations. Asset retirement obligations represent the estimate of fair value of the cost to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. We estimate the fair value of an asset’s retirement obligation in the period in which the liability is incurred, if a reasonable estimate can be made. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. We employ a present value technique to estimate the fair value of an asset retirement obligation, which reflects certain assumptions and requires significant judgment, including an inflation rate, its credit-adjusted, risk-free interest rate, the estimated settlement date of the liability and the estimated current cost to settle the liability based on third-party quotes and current actual costs. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.

Equity-Based Compensation. The Partnership awards common units under its long-term incentive plan. The related expenses reflected in the financial statements are based on the fair value of the Partnership’s equity instruments as of the grant date fair value of those instruments. That cost is recognized as compensation expense over the requisite service period (generally the vesting period).

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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.

Accounting for Business Combinations. Accounting for the acquisition of a business is accomplished by recording each asset and liability at its estimated fair value. Any excess of the purchase price over the fair value of the assets and liabilities acquired is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the values attributed to assets acquired and liabilities assumed relative to the total acquisition cost. In estimating the fair values of assets acquired and liabilities assumed, the Company makes various assumptions. The fair value measurements of assets acquired and liabilities assumed are based on various inputs. Fair value is typically estimated using comparable market data, a discounted cash flow method, or another method as discussed below. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of applicable sales estimates, operational costs and a risk-adjusted discount rate. Fair value for intangible assets acquired was primarily determined using a discounted cash flow model or multi-period excess earnings model under the income approach, which factors in discount rates, probability factors and forecasts. The fair values of property, plant and equipment acquired were primarily based on a cost approach using an indirect cost methodology to determine replacement cost. The inputs, as noted above, used to determine fair value required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Carrying value for current assets and liabilities acquired is typically representative of fair value due to their short term nature.

New Accounting Pronouncements. For a discussion of recently adopted accounting standards and recent accounting standards not yet adopted, see “Note 1 - Summary of Significant Accounting Policies” to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.

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, 2012, 2013 and 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States 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.	QUANTITAVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil, natural gas and NGL production. Due to the volatility of commodity prices, we periodically enter into derivative contracts to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations for a portion of our oil, natural gas and NGL production. While the use of derivative contracts limits our ability to benefit from increases in the prices of oil, natural gas and NGLs, it also reduces the Partnership’s potential exposure to adverse price movements. Our derivative contracts apply to only a portion of our expected production, provide only partial price protection against declines in market prices and limit our potential gains from future increases in market prices. We do not enter into derivative contracts for speculative or trading purposes.

Our hedging strategy includes entering into commodity derivative contracts for a portion of our estimated total production over a three- to five-year period at any given point in time. 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, natural gas, and NGL 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.

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At December 31, 2014, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:



Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.

Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.

Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the put option and the fixed price.

Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The following tables present our derivative instruments outstanding as of December 31, 2014:



Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2015	42,649	$	80.00	$	93.25



Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	36,500	$	77.50	$	92.50	$	102.60



Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2015	1,362,382	$	4.00	$	4.32



Natural gas put options	Volumes (MMBtu)	Floor Price
2015	798,853	$	3.50
2016	930,468	$	3.50



Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	39,411	$	88.90
2016	36,658	$	86.00



Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2015	800,573	$	4.25
2016	629,301	$	4.37

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NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	84,793	$	75.18

Our derivative contracts are based on WTI futures prices for oil, Henry Hub future prices for natural gas and Conway and Mont Belvieu future prices for NGLs. We are generally required to settle our commodity derivatives within five days of the end of the month.

The following table reflects the Partnership's percentage of production hedged through 2016.



	Oil	Natural Gas	NGLs	Total
2015	76%	67%	30%	58%
2016	28%	26%	—%	18%

Because the Partnership has not designated any of its derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts are recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price.

Gain (loss) on derivatives, net. The following table presents gain (loss) on our derivative contracts for the years ended December 31, 2014, 2013 and 2012 (in thousands):



	Year Ended December 31,
	2014		2013			2012
Total gain (loss) on derivative contracts, net (1)	$	10,707	$	(5,548	)	$	7,057

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(1)	Included in the gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of ($1.8) million, ($1.9) million and $6.0 million, respectively.

Our derivative contracts are not designated as accounting hedges and, as a result, gains or losses on commodity derivative contracts are recorded each quarter as a component of operating expenses. In general, cash is received on settlement of contracts due to lower oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps, and cash is paid on settlement of contracts due to higher oil, natural gas and NGL prices at the time of settlement compared to the contract price for our oil, natural gas and NGL price swaps.

Gain on derivative contracts was $10.7 million in 2014 compared to loss on derivative contracts of $5.5 million in 2013. The gain on derivative contracts in 2014 was primarily due to lower oil, natural gas and NGL prices at December 31, 2014 compared to the contract price or prices at December 31, 2013.

Loss on derivative contracts was $5.5 million in 2013 compared to gain on derivative contracts of $7.1 million in 2012. The loss is primarily the result of higher natural gas and NGLs settlement and futures prices in the 2013 period compared with the 2012 period. In July 2012, we liquidated all of our oil, natural gas and NGLs 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.

See "Note 6 - Derivative Contracts" to the accompanying consolidated financial statements included in Item 8 “Financial Statements and Supplementary Data” of this report for additional information regarding our commodity derivatives.

Credit Risk

All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an "investment grade" credit rating. We monitor on an ongoing basis the credit ratings of our derivative counterparties and considers our counterparties’ credit default risk ratings in determining the fair value of our derivative contracts. Our derivative contracts are with multiple counterparties to minimize the exposure to any individual counterparty. A default by the Partnership under its credit facility constitutes a default under its derivative contracts with counterparties that are lenders under the credit facility. We do not require collateral or other security from counterparties to

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support derivative instruments. We have master netting agreements with all of our derivative contract counterparties, which allows us to net our derivative assets and liabilities with the same counterparty. As a result of the netting provisions, the Partnership’s maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts. The Partnership’s loss is further limited as any amounts due from a defaulting counterparty that is a lender under the credit facility can be offset against amounts owed, if any, to such counterparty under the credit facility. As of December 31, 2014, the majority of our open derivative contracts are with counterparties that share in the collateral supporting the credit facility. As a result, we are not required to post additional collateral under its derivative contracts.

Interest Rate Risk

At December 31, 2014, the Partnership had debt outstanding under its credit facility of $83.0 million. A 1% increase in LIBOR on the Partnership outstanding debt under its credit facility as of December 31, 2014 would result in an estimated $0.8 million increase in annual interest expense.



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Partnership's consolidated financial statements required by this item are included in this report beginning on page F-1.



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

Our management, under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our audit committee, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2014. The term "disclosure controls and procedures," as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2014 at the reasonable assurance level due to the material weaknesses in internal control over financial reporting we identified in connection with preparing the 2013 Form 10-K, the Quarterly Reports for the periods ended June 30, 2014 and September 30, 2014 and this annual report. The material weaknesses we identified, as disclosed in the 2013 Form 10-K and herein, relate to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review, an inaccurate revenue cutoff on an acquired business and insufficient resources, and the lack of a sufficient number of qualified personnel to timely and appropriately account for and disclose the impact of complex, non-routine transactions in accordance with GAAP. These non-routine transactions impacted the recording of equity-based compensation, cash flow presentations, revenue, business combination adjustments, contingent consideration and disclosures and calculation of earnings (loss) per unit. The material weaknesses resulted in the recording of adjustments identified by our independent registered public accounting firm to our financial statements for the periods ended December 31, 2013, June 30, 2014, September 30, 2014 and December 31, 2014. Notwithstanding the existence of the material weaknesses, management has concluded that the financial statements included in this report present fairly, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with GAAP.

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Management’s Report on Internal Control Over Financial Reporting

The Partnership's management is responsible for establishing and maintaining adequate "internal control over financial reporting" as such term is defined in the Exchange Act Rule 13a-15(f). The Partnership’s internal control over financial reporting is a process designed under the supervision of its Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Partnership’s financial statements for external purposes in accordance with generally accepted accounting principles. As of December 31, 2014, the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of its internal control over financial reporting established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on the results of this evaluation, the Partnership's management concluded financial controls were not effective as of December 31, 2014. The material weaknesses we identified related to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review, an inaccurate revenue cutoff on an acquired business and insufficient resources, and the lack of a sufficient number of qualified personnel to timely and appropriately account for and disclose the impact of complex, non-routine transactions in accordance with GAAP. These non-routine transactions impacted the recording of equity-based compensation, cash flow presentations, revenue, business combination adjustments and disclosures, fair value of reporting units in determining impairment of goodwill and other intangibles and calculation of earnings (loss) per unit. The material weaknesses resulted in the recording of adjustments identified by our independent registered public accounting firm to our financial statements for the periods ended December 31, 2013, June 30, 2014, September 30, 2014 and December 31, 2014. Notwithstanding the existence of the material weaknesses, management has concluded that the consolidated financial statements included in this report present fairly, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with United States generally accepted accounting principles. Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of EFS and RPS, which were acquired on June 26, 2014, and which are included in the consolidated balance sheet of the Partnership as of December 31, 2014, and the related consolidated statements of operations, unitholders’ equity, and cash flows for the year then ended. EFS and RPS constituted 34% and 50% of total assets and net assets as of December 31, 2014, and 37% and 14% of revenues and net loss, respectively, for the year then ended. Management did not assess the effectiveness of internal control over financial reporting of EFS and RPS because of the timing of the acquisition, which was completed on June 26, 2014.

Attestation Report of the Registered Public Accounting Firm

This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm due to the exemption provided by the JOBS Act for emerging growth companies.

Management's Remediation Activities

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

As of December 31, 2014, we have not yet been able to remediate these material weaknesses. However, we have hired additional personnel with experience in technical accounting research and financial reporting. Additionally, we are in the process of making enhancements to our accounting and reporting processes and changing processes in order to address the material weaknesses identified. We do not know the specific timeframe needed to remediate all of the control deficiencies underlying these material weaknesses. In addition, we may need to incur incremental costs associated with this remediation, primarily due to employee recruitment and retention and engagement with third-party consulting firms, and the implementation and validation of improved accounting and financial reporting procedures. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address the material weaknesses.

Changes in Internal Control over Financial Reporting

Since the acquisition of EFS and RPS on June 26, 2014, the Partnership has been aligning EFS’ and RPS' controls to the Partnership’s existing control environment. As this process was ongoing as of December 31, 2014, it was not possible for the Partnership to perform an assessment of EFS’ or RPS' internal control over financial reporting as of December 31, 2014. Management expects that EFS' and RPS’ controls will be aligned and integrated into the Partnership’s control environment within one year of the date of the acquisition and will include EFS and RPS in its assessment of the effectiveness of internal control over financial reporting as of December 31, 2015. EFS and RPS are wholly-owned subsidiaries whose combined total assets and total revenues represent 34% and 37%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2014.

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Inherent Limitations on Effectiveness of Controls

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, even if determined effective and no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives to prevent or detect misstatements. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.



ITEM 9B.	OTHER INFORMATION

None.

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. As of March 6, 2015, our general partner is owned 69.4% by an entity controlled by Kristian B. Kos, Chairman and Chief Executive Officer of our general partner, 5.6% by NSEC and 25.0% by an entity controlled by David J. Chernicky, the former Chairman of the board of directors of our general partner.

Our general partner has a board of directors (“Board” or “Board of Directors”) that oversees its management, operations and activities. The directors of our general partner are 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 indebtedness incurred by us to be 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.

Directors and Executive Officers

The following table sets forth certain information regarding the directors and executive officers of our general partner as of March 6, 2015.



Name	Age	Position
Kristian B. Kos	37	Chairman of the Board and Chief Executive Officer
Dikran Tourian	38	Director, President and Chief Operating Officer
Richard D. Finley	64	Chief Financial Officer and Treasurer
Amber N. Bonney	40	Vice President Accounting and Principal Accounting Officer
Carol T. Bryant	57	Senior Engineer
J. Carter Robinson	37	Vice President Administration
Tom R. Russell	38	Vice President, Senior Counsel and Corporate Secretary
John A. Raber	61	Director
Charles Lee Reynolds III	64	Director
Terry L. Toole	70	Director
V. Bruce Thompson	67	Director

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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. 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. Mr. Kos currently owns 69.4% of our general partner.

Kristian B. Kos. Mr. Kos was appointed Chairman in August 2014 and has served as Chief Executive Officer, as well as a director, of our general partner since October 2012. Mr. Kos previously served as our President from August 2012 until October 2014. Mr. Kos also currently serves as chief executive officer of the general partner of MCLP. Mr. Kos served as the president and chief executive officer and director of NSEC from July 2011 until May 2014. Mr. Kos has been involved in various aspects of energy industry from 2005 through 2012 providing consulting services and managing his private investments, including founding the Partnership in 2012 and MCLP with Mr. Tourian in 2010. Prior to entering the energy industry, Mr. Kos worked in the financial sector for hedge fund manager Wexford Capital LP. 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.

The Board believes that Mr. Kos’ senior management experience for the Partnership, his prior service at other energy companies, and his background in energy-focused investing and capital raising activities qualifies him to serve on the Board.

Dikran Tourian. Mr. Tourian was appointed President and Chief Operating Officer of our general partner in October 2014. Prior to that time, he served as President - Oilfield Services Division, a position he has held since November 2013. Mr. Tourian has also served on our general partner’s board of directors since his appointment in February 2014 pursuant to the terms of a director designation agreement entered into in conjunction with the Partnership’s acquisition of MCE. Mr. Tourian also currently serves as President and Chief Operating Officer of the general partner of MCLP. Prior to joining the Partnership, Mr. Tourian was the co-founder and president of MCE. Since 2000, Mr. Tourian has founded and sold numerous businesses, including a sale of PrimaTech Medical Systems to Compass Diversified Holdings in 2007. He has a strong track record in spearheading consolidations and turnarounds across numerous highly competitive industries from health care to oilfield services. A native of western Oklahoma, Mr. Tourian earned a marketing degree from the Price School of Business at the University of Oklahoma in 1999.

Our board believes that Mr. Tourian’s experience with mergers and acquisitions and his background in the oilfield services industry qualifies him to serve on the Board.

Richard D. Finley. Mr. Finley was appointed Chief Financial Officer and Treasurer of our general partner in August 2012. Mr. Finley also served as the chief financial officer and treasurer of NSEC from August 2011 until May 2014 and was a partner at Finley & Cook, PLLC. 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 (now, the University of Central 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.

Amber N. Bonney. Ms. Bonney was appointed Vice President Accounting and Principal Accounting Officer of our general partner in February 2015. Prior to that time, Ms. Bonney served as our general partner's Director of Financial Reporting, having assumed that role in May 2014. Ms. Bonney also serves as Vice President Accounting and Principal Accounting Officer for MidCentral Energy GP, LLC. Prior to joining the Partnership, Ms. Bonney served in various capacities, including as controller, at SandRidge Energy, Inc. from March 2008 until May 2014, where she was responsible for the company’s financial reporting and involved in a variety of notable transactions, including acquisitions, divestitures, debt and equity offerings and initial public offerings for three royalty trusts. Ms. Bonney worked in the internal audit group at Devon Energy Corporation and was a manager at PricewaterhouseCoopers LLP prior to her time at SandRidge Energy, Inc. Ms. Bonney earned a Bachelor of Business Administration with majors in accounting and finance from the University of Oklahoma and is a Certified Public Accountant.

Carol T. Bryant. Ms. Bryant was appointed Senior Engineer of our general partner in August 2012. Ms. Bryant also served as a senior engineer for NSEC from August 2011 to December 31, 2013 and 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 Gulfport Energy Corp and some of its affiliates, 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

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positions with Chaparral Energy, LLC in Oklahoma City. Ms. Bryant graduated from the University of Tulsa in 1980 with a Bachelor of Science degree in Petroleum Engineering.

J. Carter Robinson. Mr. Robinson was appointed Vice President Administration of our general partner in February 2015. Mr. Robinson previously served as our general partner's Director of Administration, having assumed that role in May 2014. Mr. Robinson also serves as Vice President Administration for MidCentral Energy GP, LLC. Prior to joining the Partnership, Mr. Robinson served in various capacities with MCES from April 2011 until May 2014, including as President of MCES’ BOP Division. Prior to joining MCES, Mr. Robinson was a member of the management team of B.O.P. Ram-Block & Iron Rentals, Inc. from January 2002 until April 2011. Mr. Robinson graduated from the Meinders School of Business at Oklahoma City University with a Masters of Energy Management and Masters of Business Administration and has also earned a Bachelor of Science with a major in healthcare administration from Southwestern Oklahoma State University.

Tom R. Russell. Mr. Russell was appointed Vice President, Senior Counsel and Secretary of our general partner in February 2015. Mr. Russell previously served as Senior Counsel for our general partner, having assumed that role in April 2014. Mr. Russell also serves as Vice President, Senior Counsel and Secretary for MidCentral Energy GP, LLC. Prior to joining the Partnership, Mr. Russell served as in-house counsel at SandRidge Energy, Inc. from October 2008 until April 2014 and practiced corporate and securities laws at Crowe & Dunlevy P.C. prior to that time period. Mr. Russell also sits on the board of directors of the City Rescue Mission in Oklahoma City. Mr. Russell graduated from the University of Oklahoma College of Law and also earned a Masters of Business Administration from Oklahoma State University and a Bachelor of Administration with a major in finance from Northeastern State University.

John A. Raber. Mr. Raber was appointed to serve as a member of the board of directors of our general partner in May 2013. Mr. Raber has over 37 years of experience working in the energy sector. Mr. Raber was an Executive Vice President of Copano Energy, L.L.C. (“Copano”) from June 2005 to August 2010, President of Copano’s Rocky Mountain assets from September 2007 to August 2010 and President of Copano’s Mid-Continent and Rocky Mountain assets from June 2005 to September 2007. Prior to joining Copano, Mr. Raber helped form ScissorTail Energy, LLC in June 2000 and served as its President and Chief Operating Officer until it was purchased by Copano in June 2005. From July 1999 to June 2005, Mr. Raber was Vice President of Marketing and Business Development for Wyoming Refining Company and from February 1995 to July 1999, Mr. Raber was a Senior Vice President and held other positions with Tejas Gas Corporation. Mr. Raber was Vice President of Operations and Engineering and held other positions with LEDCO, Inc., an integrated energy company, from June 1982 to February 1999, and he worked overseas for J. Ray McDermott in various engineering and operations capacities from May 1976 to June 1982. Mr. Raber graduated from Tulane University in May 1976 with a Bachelor of Science degree in Civil Engineering and has also attended Stanford University’s Executive Business School.

The Board believes that Mr. Raber’s knowledge of the midstream business and business development within the energy sector, as well as his significant senior management experience, qualifies him to serve on the Board.

Charles Lee Reynolds III. Mr. Reynolds was appointed to serve as a member of the board of directors of our general partner in February 2014. Mr. Reynolds is Practice Leader of the North American Exploration and Production Energy Insurance Practice for Arthur J. Gallagher Risk Management Services, Inc. (“AJG”). Mr. Reynolds is responsible for providing risk management and insurance brokerage expertise to clients of AJG and to assure that the firm consistently provides a full spectrum of specialized professional services. Prior to taking his current position with AJG in 2011, Mr. Reynolds was the founder and president of Meyers-Reynolds & Associates, Inc. with offices in Oklahoma City and Tulsa, Oklahoma. Meyers-Reynolds specialized in providing professional risk management and insurance brokerage services to clients in the energy space on a global basis. In addition to experience in the United States, during his 37 year career, Mr. Reynolds has handled or consulted on energy risks in Argentina, Australia, Bulgaria, the Czech Republic, the Caribbean, China, Colombia, France, Guatemala, India, Indonesia, Spain, the United Kingdom and Venezuela. Mr. Reynolds received a Bachelor of Arts degree from the University of Oklahoma in 1974 and a Masters of Business Administration degree from Oklahoma City University in 1976.

The Board believes that Mr. Reynolds’ vast knowledge of, and experience dealing with, issues relating to risk management in the energy space qualifies him to serve on the Board.

V. Bruce Thompson. Mr. Thompson was appointed to serve as a member of the board of directors of our general partner in August 2012. Mr. Thompson served as general counsel of NSEC from August 2011 to August 2012. 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 32 of America’s leading independent oil, natural gas, and NGL 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. (“SandRidge”). 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,

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Mr. Thompson served as senior vice president and general counsel of Forest Oil Corporation. Mr. Thompson also served as chief of staff for United States Senator James Inhofe when Mr. Inhofe was in the United States House of Representatives. 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.

The board of directors believes Mr. Thompson’s knowledge of the oil and gas industry and the legal challenges faced by industry participants, as well as his previous public company experience qualifies him to serve on the board.

Terry L. Toole. Mr. Toole was appointed to serve as a member of the board of directors of our general partner in August 2012. Mr. Toole served as a director of NSEC from January 2012 until January 2013. 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 with a concentration in Economics from Fort Hays State University in 1966 and a Master’s degree in Business Administration with a concentration in Accounting in 1968 from West Texas A&M University. 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.

The board believes 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.

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. Mr. Kos was appointed Chairman in October 2014 and currently serves as both Chairman and Chief Executive Officer of our general partner. Our President and Chief Operating Officer, Mr. Tourian, also serves as a director. The Board has not appointed a lead independent director. For the reasons discussed below, the Board believes this is the most appropriate leadership structure at this time.

Mr. Kos’ service as the Board’s Chairman, and Mr. Tourian’s service as a director, allows the Board to act efficiently and effectively to best serve the interests of our unitholders and the Partnership as a whole. The Chief Executive Officer and Chief Operating Officer bear primary responsibility for managing the day-to-day business of the Company and are best suited to bring key business issues and unitholders’ interests to the attention of the Board.

The Board does not believe that the Partnership’s leadership structure would be enhanced appreciably by splitting the roles of Chairman and Chief Executive Officer at this time. The Board follows sound corporate governance practices to ensure its independence and effective functioning, as described in detail below. The independent directors regularly meet in executive session without management directors present. In addition, the Board’s committees are composed entirely of independent directors, which means that oversight of critical issues such as the integrity of the Partnership’s financial statements is entrusted to independent directors.

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.

None of our executive officers serves as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our Board of Directors.

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 Messrs. Toole, Raber, Reynolds and Thompson are “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.

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Director Attendance at Meetings of the Board of Directors

The Board of Directors held 11 meetings during 2014, and each of the directors attended 75% or more of the combined total meetings of the Board and the respective committees on which he served.

The non-management directors of our general partner meet in executive session periodically throughout the year. At least once a year, these executive sessions include only directors who qualify as independent under the listing requirements of the NYSE. A lead director for each meeting of non-management directors is designated by the directors present at each such meeting. The lead director is responsible for preparing an agenda for the meetings of the non-management or independent directors in executive session.

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. Currently, the Audit Committee is comprised of Messrs. Toole, Raber and Reynolds. Mr. Toole serves as chairman of the committee. The Board of directors has determined that each of Messrs. Toole, Raber and Reynolds are financially literate and “independent” under the standards of the NYSE and SEC regulations currently in effect. Additionally, the Board has determined that Mr. Toole is an “audit committee financial expert” under SEC guidelines. The Audit Committee assists the board of directors in its oversight of the integrity of our consolidated 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. The Audit Committee has a written charter adopted by the Board, which is available on our website at http://www.newsource.com/Investors/Corporate-Governance.

Conflicts Committee

Messrs. Toole, Raber and Reynolds comprise our Conflicts Committee. The Conflicts Committee determines 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.

Compensation Committee

As a limited partnership, we are not required by the NYSE to establish a compensation committee. However, in October 2014, the Board formed a compensation committee. Our compensation committee works with our senior management to review and recommend compensation for our executive officers. Mr. Thompson is the chairman and sole member of the committee.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our officers and directors and persons who own more than 10% of our common units outstanding to file reports of ownership and changes in ownership concerning their shares of our common stock with the SEC and to furnish us with copies of all Section 16(a) forms they file. We are required to disclose delinquent filings of reports by such persons.

Based solely on the copies of such reports and amendments thereto received by us, or written representations that no filings were required, we believe that all Section 16(a) filing requirements applicable to our executive officers and directors and 10% unitholders were met for the fiscal year ended December 31, 2014, except for two Forms 4 filed by Mr. Chernicky on September 30, 2014 (relating to three separate transactions) and October 14, 2014 (relating to four separate transactions), after his resignation from the Board of Directors.

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Corporate Governance

The Board 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 www.newsource.com/Investors, 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.

Communications with Directors

The Board welcomes communications from our unitholders and other interested parties. Unitholders and any other interested parties may send communications to the Board, any committee of the Board, the chairman of the Board or any other director in particular to:

New Source Energy Partners L.P.

914 North Broadway, Suite 230

Oklahoma City, Oklahoma 73102

Unitholders and any other interested parties should mark the envelope containing each communication as “Communication with Directors” and clearly identify the intended recipient(s) of the communication. The head of our general partner’s legal department will review each communication received from unitholders and other interested parties and will forward the communication, as expeditiously as reasonably practicable, to the addressees if: (1) the communication complies with the requirements of any applicable policy adopted by the board of directors of our general partner relating to the subject matter of the communication; and (2) the communication falls within the scope of matters generally considered by the board. To the extent the subject matter of a communication relates to matters that have been delegated by the board to a committee or to an executive officer of our general partner, then the head of our general partner’s legal department may forward the communication to the executive officer or chairman of the committee to which the matter has been delegated. The acceptance and forwarding of communications to the members of the Board or an executive officer does not imply or create any fiduciary duty of the board members or executive officer to the person submitting the communications.



ITEM 11.	EXECUTIVE COMPENSATION

Compensation Overview

Executive Summary

We are currently considered an emerging growth company for purposes of the SEC’s executive compensation disclosure rules. In accordance with such rules, we are required to provide a summary compensation table and a summary of our outstanding equity awards, as well as limited narrative disclosures. Further, our executive compensation disclosure obligations extend only to the individual serving as our principal executive officer and our two other most highly compensated executive officers. The individuals we considered to be our “named executive officers” for the year ended December 31, 2014 are:


•	Kristian B. Kos, Chairman and Chief Executive Officer


•	Dikran Tourian, President and Chief Operating Officer


•	Carol T. Bryant, Senior Engineer


•	Richard D. Finley, Chief Financial Officer

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Although Mr. Tourian did not serve as our principal executive officer during 2014 and was not one of our two other most highly compensated executive officers during 2014, we have included him as a named executive officer for purposes of this Item 11 because he performs functions for our general partner that are very similar to those performed by our principal executive officer.

Summary Compensation Table



Name and Principal Position	Year	Salary		Bonus (1)		Equity Awards (2)		All Other Compensation		Total (3)
Kristian B. Kos	2014	$	360,000	$	—	$	—	$	2,250	$	362,250
Chairman and Chief Executive Officer	2013	$	—	$	—	$	3,125,738	$	—	$	3,125,738
Dikran Tourian	2014	$	143,750	$	—	$	—	$	870	$	144,620
President and Chief Operating Officer
Carol T. Bryant	2014	$	187,500	$	68,000	$	—	$	1,917	$	257,417
Senior Engineer	2013	$	—	$	—	$	467,400	$	—	$	467,400
Richard D. Finley	2014	$	192,000	$	—	$	—	$	1,440	$	193,440
Chief Financial Officer	2013	$	—	$	—	$	467,400	$	—	$	467,400

_______________


(1)	Represents cash bonus paid of $18,000 in 2014 and $50,000 in 2015.

(2)

Amounts in this column reflect the grant date fair value of equity awards granted, calculated in accordance with the Financial Accounting Standards Board's Accounting Standards Codification Topic 718 "Compensation - Stock Compensation," disregarding any risk of forfeiture. See "Note 9 - Equity" to the consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” of this report for a more detailed discussion of the assumptions used to calculate the value of these awards.


(3)	For 2013, amounts in this column reflect only the value of equity awards that were granted to Mr. Kos. NSEC was responsible for all other compensation that may have been paid to our named executive officers for 2013.

Narrative Disclosure to the Summary Compensation Table

Compensation for the 2013 Fiscal Year

During the year ended December 31, 2013, our named executive officers were directly employed by NSEC, and NSEC made all compensation decisions and provided compensation payments to our named executive officers. Due to the structure of the omnibus agreement between us and NSEC, neither we nor NSEC considered the compensation that NSEC provided to the named executive officers to have been allocated to us at any time during the year ended December 31, 2013.

Although NSEC did not allocate compensation costs to us in 2013, our general partner recognized the contribution of our named executive officers during our IPO in February 2013. In recognition of their efforts, 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 (“LTIP”) during February 2013, as described in more detail below. In accordance with the terms of the omnibus agreement, we are solely responsible for all costs associated with the grants of awards under the LTIP, thus the Summary Compensation Table above reflects the LTIP grants that we made to our named executive officers in 2013.

Compensation for the 2014 Fiscal Year

Beginning in the first quarter of 2014, our named executive officers were employed directly by our general partner. Therefore, all compensation paid to our named executive officers during 2014 is reflected in the Summary Compensation Table above.

Equity Compensation

In connection with the IPO, the Board adopted the LTIP for employees, officers, consultants and directors of our general partner and any of its affiliates who perform services for us. Upon the closing of the IPO, the Board granted restricted unit awards to certain officers and directors of our general partner, including Mr. Kos, Ms. Bryant and Mr. Finley. The restricted period associated

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with these initial restricted unit awards will expire at the end of the subordination period (as described in our partnership agreement), at which time the holders will receive unrestricted common units. Mr. Kos, Ms. Bryant and Mr. Finley are entitled to receive quarterly distributions during the restricted period.

In addition to awards granted under the LTIP at our IPO, the Board granted the following awards to our named executive officers on January 9, 2015 for service performed during 2014: Mr. Kos - 108,225 common units; Mr. Tourian - 108,225 common units and Ms. Bryant - 7,174 restricted units. The common unit awards to Mr. Kos and Mr. Tourian vested immediately. The restricted units awarded to Ms. Bryant vest ratably over a three-year vesting term and Ms. Bryant is entitled to receive quarterly distributions during the restricted period.

Outstanding Equity Awards at Fiscal Year End

The following table reflects all outstanding equity awards held by each of our named executive officers as of December 31, 2014:



	Stock Awards
Name	Number of Shares or Units of Stock That Have Not Vested (1)	Market Value of Shares or Units of Stock That Have Not Vested (2)
Kristian B. Kos	133,750	$	963,000
Dikran Tourian	—	$	—
Carol T. Bryant	20,000	$	144,000
Richard D. Finley	20,000	$	144,000

_______________


(1)	These awards consists entirely of restricted units granted pursuant to the LTIP, which will vest at the end of the subordination period.


(2)	The market value of the restricted units was calculated by multiplying the number of restricted units outstanding by the closing price of our common units on December 31, 2014 of $7.20.

Additional Narrative Disclosure

Retirement Benefits

We have not maintained, and do not currently maintain, a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits. Our named executive officers currently participate in our 401(k) plan, which permits all eligible employees, including the named executive officers, to make voluntary pre-tax contributions to the plan. The plan also provides matching contributions equal to 100% of eligible employees' pre-tax contributions that do not exceed 3% of their eligible compensation. All contributions under the plan are subject to certain annual dollar limitations, which are periodically adjusted for changes in the cost of living.

Severance and Change in Control Benefits

We do not maintain employment agreements or severance agreements with our named executive officers, but our current restricted unit award agreements under the LTIP contain provisions that could accelerate vesting of the award in certain situations. In the event that one of the named executive officers is terminated by us or one of our affiliates prior to the vesting date of the restricted unit award for cause, all restricted units will immediately be forfeited without consideration. In the event of the executive’s death, or if we consummate a change in control, all restricted units will become 100% vested. If we or one of our affiliates terminate the executive for a reason other than for cause or due to the executive’s death prior to vesting, the award may continue to vest on the regular vesting schedule so long as the executive remains in compliance with the non-compete and non-solicitation provisions in the applicable award agreement.

The LTIP generally defines a “Change in Control” as occurring on one or more of the following events: (i) any person or group, other than members of our general partner, us or an affiliate of either our general partner or us, becomes the beneficial owner, by way of a merger, consolidation, recapitalization or otherwise, of 50% or more of the voting power of our general partner’s or our voting securities; (ii) the limited partners of our general partner or our limited partners approve a plan of complete liquidation; (iii) the sale or other disposition by our general partner of all or substantially all of its assets or by us of all or substantially all of

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our assets to a person that is not an affiliate; (iv) our general partner or an affiliate of our general partner or of us ceases to be our general partner; or (v) any other event specified as a “change in control” within an LTIP award agreement.

The restricted unit agreements generally define “Cause” as one or more of the following events: (i) the executive’s willful engagement in dishonesty, illegal conduct or gross misconduct, in each case, that is or could reasonably be expected to be materially injurious to our or any of our affiliates' financial condition or business reputation; (ii) the executive’s embezzlement, misappropriation or fraud, whether or not related to the executive’s employment with the us or one of our affiliates; (iii) the executive’s conviction of or plea of guilty or nolo contendere to a crime that constitutes a felony, or a crime that constitutes a misdemeanor that involves moral turpitude; or (iv) the executive’s breach of fiduciary duties to us or our affiliates that results in material harm to us or our affiliates.

Director Compensation

In 2014, each of the non-employee members of the Board received an annual cash retainer of $100,000. In addition, the non-employee directors received $200 per hour for time spent serving on committees or for completing special projects. In December 2014, the Board agreed that director compensation for 2015 would be $165,000, consisting of an annual cash retainer of $65,000 and an annual grant of common units valued at $100,000. In addition, the Board approved an annual committee chair fee of $15,000 and committee meeting fees of $1,000 for meetings attended in person and $500 for meetings attended telephonically.

The following table sets forth the compensation of our non-employee directors for the fiscal year ended December 31, 2014.



Name	Fees earned or paid in cash		Stock Awards	Total
Terry L. Toole	$	134,919	-	$	134,919
V. Bruce Thompson	$	138,125	-	$	138,125
Phil Albert(1)	$	110,000	-	$	110,000
Charles Lee Reynolds III(2)	$	70,000	-	$	70,000
John A. Raber	$	130,590	-	$	130,590

_______________


(1)	Resigned December 19, 2014.


(2)	Appointed in February 2014.



ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Equity Compensation Plan Information

The following table includes certain information as of December 31, 2014 regarding our equity incentive plans:




Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted-average exercise price of outstanding options, warrants and rights(3)	(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by unitholders New Source Energy Partners L.P. Long-Term Incentive Plan(1)	—	—	390,057
Equity compensation plans not approved by unitholders New Source Energy Partners L.P. Fair Market Value Purchase Plan(2)	—	—	—
Total	—	—	390,057

_______________

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(1)	The New Source Energy Partners L.P. Long-Term Incentive Plan (the “LTIP”) was approved by our general partner prior to the initial public offering of our common units.

(2)

The New Source Energy Partners L.P. Fair Market Value Purchase Plan merely provides a convenient way to purchase common units on the open market at fair market value and, therefore, no unitholder approval was required under the applicable New York Stock Exchange rules since the plan is not considered to be an equity compensation plan under these rules. As of December 31, 2014, the only awards issued under this plan were issued in conjunction with the Services Acquisition in June 2014.


(3)	To date, only restricted unit awards have been granted under the LTIP and there is no exercise price associated with such awards.

Security Ownership of Certain Beneficial Ownership and Management

The following table sets forth the number of common units beneficially owned as of March 6, 2015 by (1) those persons or any group (as that term is used in Section 13(d)(3) of the Exchange Act) known to beneficially own more than 5% of the outstanding shares of our common stock, (2) each named executive officer and director of our general partner, and (3) all directors and executive officers of our general partner as a group. For purposes of this table, beneficial ownership is determined in accordance with Rule 13d-3 under the Exchange Act. The following percentage information is calculated based on 16,403,134 common units that were outstanding as of March 6, 2015. Except as indicated below, the unitholders listed possess sole voting and dispositive power with respect to the shares beneficially owned by that person. Unless otherwise noted, the mailing address of each person named below is 914 North Broadway, Suite 230, Oklahoma City, Oklahoma 73102.



Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Common and Subordinated Units Beneficially Owned
Kristian B. Kos(1)	924,737	5.6	%	—	—	%	5.0	%
Dikran Tourian(2)	790,987	4.8	%	—	—	%	4.3	%
Richard D. Finley	20,000	*		—	—	%	*
Carol T. Bryant	27,174	*		—	—	%	*
John A. Raber	300	*		—	—	%	*
Charles Lee Reynolds III	—	*		—	—	%	*
Terry L. Toole	5,000	*		—	—	%	*
V. Bruce Thompson	5,000	*		—	—	%	*
Goldman Sachs Asset Management L.P.(3)	1,868,732	11.4	%	—	—	%	10.0	%
Erick's Holdings, LLC(4)	1,411,777	8.6	%	—	—	%	7.6	%
David Chernicky(5)	2,468,421	15.1	%	2,205,000	100.0	%	25.3	%
All executive officers and directors as a group (eight persons)	1,773,198	10.8	%	—	—		9.5	%

_______________

* Represents less than 1% of the outstanding common units.


(1)	Includes common units held by Deylau, LLC, which is owned 100% by Mr. Kos.


(2)	Includes common units held by Signature Investments, LLC, which is owned 100% by Mr. Tourian.


(3)	According to a Schedule 13G/A filed with the SEC on February 12, 2015, the common units listed in the table above are beneficially owned by Goldman Sachs Asset Management, L.P. and GS Investment Strategies, LLC (collectively, "GSAM"). The business address for GSAM is 200 West Street, New York, NY 10282.


(4)	Erick's Holdings, LLC is owned 50% by Mark Snodgrass and 50% by Bryan Austin. Mr. Snodgrass is Senior Vice President Operations of MidCentral Energy GP, LLC. The address for Erick's Holdings, LLC is Two Leadership Square, 10th Floor, Oklahoma City, OK 73102.

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(5)	According to a Form 4 filed on February 18, 2015. Includes common units held by NSEC and Scintilla, LLC and subordinated units held by NSEC, which are owned, 88.9% and 100% by Mr. Chernicky. The address for each of NSEC and Scintilla, LLC is 1307 South Boulder Avenue, Tulsa, Oklahoma 74119.



ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

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 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, the Board, or the conflicts committee of the Board. The executive officers of our general partner are required to avoid conflicts of interest unless approved by the Board.

The Board has a conflicts committee comprised of three independent directors. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with transactions with related persons. The conflicts committee will be entitled to hire its own financial and legal advisors in connection with any matters on which the Board has sought the conflicts committee’s approval.

Transactions with Directors and Officers

On June 26, 2014, the Partnership entered into a Contribution Agreement with Torus Energy Services, LLC, Mr. Kos, Chief Executive Officer of our general partner, Mr. Tourian, President and Chief Operating Officer of our general partner, and Signature Investments, LLC (“Signature”), an entity wholly-owned by Mr. Tourian, to acquire all of the outstanding equity interests in MCCS for approximately $1.5 million in total initial consideration, which consisted of the assumption by the Partnership of approximately $0.8 million of debt and the issuance of 16,823 of the Partnership’s common units to each of Mr. Kos and Signature (for a total of 33,646 common units), valued using a 20-day volume weighted average trading price for the period through June 23, 2014 of $23.1461 per common unit. Mr. Kos and Signature are also entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ended March 31, 2015, less certain adjustments, and subject to a $4.5 million cap. Concurrently with the acquisition, the Partnership contributed MCCS to MCLP.

The conflicts committee of the Board reviewed the transaction and related terms and agreements and granted “special approval” with respect to the transaction pursuant to our partnership agreement. The Board approved the transaction based on the approval and recommendation of its conflicts committee, which consisted of two directors meeting the Partnership’s independence criteria and the NYSE’s listing standards for independence.

The Partnership engaged Finley & Cook, PLLC ("Finley & Cook") to provide various accounting services on our behalf during the years ended December 31, 2014. Richard Finley, the Chief Financial Officer of our general partner, was an equity member of Finley & Cook, holding a 31.5% ownership interest until October 2014. The Partnership paid Finley & Cook approximately $0.4 million in fees for the year ended December 31, 2014.

On January 9, 2015, MCLP acquired two separate parcels of land, one located in Canadian County, Oklahoma and one located in Ector County, Texas, from an entity owned 50% by Mr. Kos, Chief Executive Officer of our general partner, and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner, for approximately $0.9 million. Additionally, on February 20, 2015, MCLP acquired land located in Karnes County, Texas from an entity owned 50% by Mr. Kos and 50% by Mr. Tourian for approximately $0.5 million. The purchase price for each transaction was determined based on independent third-party appraisals for each property. In each transaction, a promissory note for the entire purchase price was issued by MCLP to Mr. Kos and Mr. Tourian. The Board approved the transaction based on the approval and recommendation of its conflicts committee, which consisted of two directors meeting the Partnership’s independence criteria and the NYSE’s listing standards for independence.

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 Messrs. Toole, Raber and Reynolds are “independent” under the standards of the NYSE and SEC regulations

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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, 2014 and 2013, the accounting fees and services charged by BDO USA, LLP, our independent auditors, were as follows:



	Year Ended December 31,
	2014		2013
	(in thousands)
Audit fees (1)	$	2,088	$	938
Audit-related fees (2)	—		428
	$	2,088	$	1,366

_______________


(1)	Audit fees represent fees for professional services rendered in connection with the audit of our annual consolidated financial statements, review of our quarterly consolidated 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.


(2)	Audit related fees represent fees to audit financial statements of acquired businesses.

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

The following documents are filed as a part of this report:

1.Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements appearing on page F-1.

2.Financial Statement Schedules

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the consolidated financial statements or notes thereto.

3.Exhibits

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS




Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2014 and 2013	F-3
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012	F-4
Consolidated Statements of Unitholders' Equity for the Years ended December 31, 2014, 2013 and 2012	F-5
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	F-6
Notes to Consolidated Financial Statements	F-8

F-1

Report of Independent Registered Public Accounting Firm

To the Partners of New Source Energy Partners L.P.

Oklahoma City, Oklahoma

We have audited the accompanying consolidated balance sheets of New Source Energy Partners, L.P. (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, unitholders' equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership’s management. 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 is not required to have, nor were we engaged to perform, an audit of its 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. 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, prior to February 13, 2013 the Partnership did not operate as a stand-alone entity. The Partnership’s financial statements prior to February 13, 2013 reflect the assets, liabilities, revenues, and expenses directly attributable to the Partnership’s operations, as well as allocations deemed reasonable by management, to present the financial position, results of operations, and cash flows of the Partnership and do not necessarily reflect the financial position, results of operations and cash flows had the Partnership operated as a stand-alone entity prior to February 13, 2013 and, accordingly, may not be indicative of the Partnership’s future performance.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2014 and 2013, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

/s/ BDO USA, LLP

Austin, Texas

March 20, 2015

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New Source Energy Partners L.P.

Consolidated Balance Sheets



	December 31,
	2014			2013
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash	$	5,504		$	7,291
Restricted cash	350			—
Accounts receivable, net	38,784			12,609
Derivative contracts	8,248			130
Inventory	4,236			162
Other current assets	3,116			822
Total current assets	60,238			21,014

Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	332,413			291,829
Less: Accumulated depreciation, depletion, and amortization	(153,734		)	(128,961		)
Total oil and natural gas properties, net	178,679			162,868
Property and equipment, net	68,886			8,166
Intangible assets, net	56,377			35,009
Goodwill	9,315			23,974
Derivative contracts	1,818			660
Other assets	2,152			3,019
Total assets	$	377,465		$	254,710

LIABILITIES AND UNITHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	15,326		$	3,267
Accounts payable-related parties	4,237			8,221
Factoring payable	13,152			1,907
Contingent consideration payable	11,572			—
Derivative contracts	—			3,167
Asset retirement obligations	113			—
Current portion of long-term debt	11,825			719
Total current liabilities	56,225			17,281
Long-term debt	95,218			80,014
Contingent consideration payable	10,801			6,320
Asset retirement obligations	3,568			3,455
Other liabilities	339			387
Total liabilities	166,151			107,457
Commitments and contingencies (Note 15)
Unitholders' equity:
Common units (16,160,381 units issued and outstanding at December 31, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	231,510			151,773
Common units held in escrow	(6,955		)	—
Subordinated units (2,205,000 units issued and outstanding at December 31, 2014 and December 31, 2013)	(28,717		)	(17,334		)
General partner's units (155,102 units issued and outstanding at December 31, 2014 and December 31, 2013)	(1,944		)	(1,174		)
Total New Source Energy Partners L.P. unitholders' equity	193,894			133,265
Noncontrolling interest	17,420			13,988
Total unitholders' equity	211,314			147,253
Total liabilities and unitholders' equity	$	377,465		$	254,710

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

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New Source Energy Partners L.P.

Consolidated Statements of Operations



	Year Ended December 31,
	2014			2013			2012
	(in thousands, except per unit amounts)
Revenues:
Oil sales	$	14,906		$	8,090		$	5,570
Natural gas sales	15,534			10,000			6,030
NGL sales	31,048			28,847			23,996
Oilfield services	104,155			3,738			—
Total revenues	165,643			50,675			35,596
Operating costs and expenses:
Oil, natural gas and NGL production	18,617			12,631			6,217
Production taxes	2,833			2,669			1,144
Cost of providing oilfield services	60,904			2,040			—
Depreciation, depletion and amortization	54,352			18,556			14,409
Accretion	327			209			116
Impairment of goodwill and other intangible assets	59,000			—			—
General and administrative	28,671			14,760			12,660
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
Total operating costs and expenses	215,673			49,265			34,546
Operating (loss) income	(50,030		)	1,410			1,050
Other income (expense):
Interest expense	(5,041		)	(4,078		)	(3,202		)
Gain (loss) on derivative contracts, net	10,707			(5,548		)	7,057
Gain on investment in acquired business	2,298			22,709			—
Other (expense) income	(9		)	3			—
(Loss) income before income taxes	(42,075		)	14,496			4,905
Income tax benefit (expense)	—			12,126			(1,796		)
Net (loss) income	(42,075		)	26,622			3,109
Less: net income attributable to noncontrolling interest	242			—			—
Net (loss) income attributable to New Source Energy Partners L.P.	$	(42,317	)	$	26,622		$	3,109

Net income prior to purchase of properties from NSEC on February 13, 2013				$	5,303
Net (loss) income subsequent to purchase of properties from NSEC on February 13, 2013 and allocable to units	$	(42,317	)	$	21,319

Net (loss) income per unit:
Net (loss) income per general partner unit	$	(2.64	)	$	1.88
Net (loss) income per subordinated unit	$	(2.84	)	$	1.86
Net (loss) income per common unit	$	(2.64	)	$	2.42

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

F-4

Table of Contents

New Source Energy Partners L.P.

Consolidated Statements of Unitholders' Equity



				Unitholders' Equity
	Parent Net Investment			Common				Subordinated				General Partner				Non-controlling Interest			Total Unitholders' Equity
	Parent Net Investment			Units	Equity			Units	Equity			Units	Equity			Non-controlling Interest			Total Unitholders' Equity
				(in thousands, except unit amounts)
Balance, December 31, 2011	$	18,420		—	$	—		—	$	—		—	$	—		$	—		$	—
Net income	3,109			—	—			—	—			—	—			—			—
Equity-based compensation	8,204			—	—			—	—			—	—			—			—
Distribution to parent	(13,758		)	—	—			—	—			—	—			—			—
Balance, December 31, 2012	15,975			—	—			—	—			—	—			—			—
Net income attributable to the period January 1, 2013 to February 12, 2013	5,303			—	—			—	—			—	—			—			—
Allocated equity-based compensation of parent	388			—	—			—	—			—	—			—			—
Distribution to parent attributable to the period January 1, 2013 to February 12, 2013	(2,495		)	—	—			—	—			—	—			—			—
Subordinated note payable to parent at closing	(25,000		)	—	—			—	—			—	—			—			—
Cash paid to parent at closing	(15,800		)	—	—			—	—			—	—			—			—
Distribution of accounts receivable to parent	(7,014		)	—	—			—	—			—	—			—			—
Accounts payable assumed by parent	1,742			—	—			—	—			—	—			—			—
Purchase of oil and natural gas properties from NSEC in exchange for units	26,901			777,500	(7,306		)	2,205,000	(18,347		)	150,000	(1,248		)	—			(26,901		)
Issuance of common units in initial public offering, net of offering costs	—			4,250,000	76,565			—	—			—	—			—			76,565
Issuance to general partner from overallotment exercised	—			—	—			—	—			5,102	—			—			—
Equity-based compensation	—			367,500	7,451			—	—			—	—			—			7,451
Purchases of oil and natural gas properties in exchange for units	—			1,792,545	36,406			—	—			—	—			—			36,406
Distributions to unitholders	—			—	(9,477		)	—	(3,086		)	—	(217		)	—			(12,780		)
Acquisition of MCE	—			1,947,033	21,372			—	—			—	—			13,988			35,360
Issuance of common units in private placement, net of offering costs	—			465,000	9,833			—	—			—	—			—			9,833
Net income attributable to the period February 13, 2013 to December 31, 2013	—			—	16,929			—	4,099			—	291			—			21,319
Balance, December 31, 2013	—			9,599,578	151,773			2,205,000	(17,334		)	155,102	(1,174		)	13,988			147,253
Issuance of common units, net of offering costs	—			4,170,000	92,375			—	—			—	—			—			92,375
Offering cost related to 2013 private placement paid in 2014	—			—	(100		)	—	—			—	—			—			(100		)
Issuance of common units in acquisitions	—			1,964,957	43,938			—	—			—	—			3,432			47,370
Equity-based compensation	—			425,846	3,233			—	—			—	—			—			3,233
Distributions to unitholders	—			—	(31,012		)	—	(5,127		)	—	(361		)	(242		)	(36,742		)
Net loss	—			—	(35,652		)	—	(6,256		)	—	(409		)	242			(42,075		)
Balance, December 31, 2014	$	—		16,160,381	$	224,555		2,205,000	$	(28,717	)	155,102	$	(1,944	)	$	17,420		$	211,314

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

F-5

New Source Energy Partners L.P. Consolidated Statements of Cash Flows

	Years Ended December 31,
	2014			2013			2012
	(in thousands)
Cash Flows from Operating Activities:
Net (loss) income	$	(42,075	)	$	26,622		$	3,109
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	54,352			18,556			14,409
Accretion	327			209			116
Impairment of goodwill and other intangible assets	59,000			—			—
Amortization of deferred loan costs	660			479			603
Write off of loan costs due to debt refinancing	167			1,436			—
Equity-based compensation	3,233			7,839			8,204
Deferred income tax benefit	—			(12,024		)	1,694
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
Gain on investment in acquired business	(2,298		)	(22,709		)	—
(Gain) loss on derivative contracts, net	(10,707		)	5,548			(7,057		)
Cash (paid) received on settlement of derivative contracts	(1,773		)	(1,929		)	5,987
Payments for premiums on derivatives	—			(1,334		)	—
Other	582			—			—
Changes in operating assets and liabilities:
Accounts receivable	(2,859		)	(10,595		)	881
Other current assets and other assets	(4,122		)	333			—
Accounts payable and accrued liabilities	(547		)	7,533			(147		)
Net cash provided by operating activities	44,909			18,364			27,799
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	(63,446		)	(22,102		)	—
Additions to oil and natural gas properties	(24,671		)	(28,921		)	(12,162		)
Additions to other property and equipment	(11,536		)	—			—
Net cash used in investing activities	(99,653		)	(51,023		)	(12,162		)
Cash Flows from Financing Activities:
Proceeds from borrowings	22,369			80,500			3,000
Payments on borrowings	(19,814		)	(70,102		)	(3,500		)
Payment on subordinated note payable to parent	—			(25,000		)	—
Payments for deferred loan costs	(536		)	(1,954		)	(64		)
(Payments on) proceeds from factoring payable, net	(4,595		)	229			—
Proceeds from sales of common units, net of offering costs	92,375			77,880			—
Proceeds from issuance of common units in private placement, net of offering costs	—			9,833			—
Payments of offering costs	(100		)	(361		)	(1,315		)
Distribution to unitholders	(36,742		)	(12,780		)	—
Distribution to NSEC	—			(18,295		)	(13,758		)
Net cash provided by (used in) financing activities	52,957			39,950			(15,637		)
Net change in cash and cash equivalents	(1,787		)	7,291			—
Cash and cash equivalents, beginning of period	7,291			—			—
Cash and cash equivalents, end of period	$	5,504		$	7,291		$	—

F-6

New Source Energy Partners L.P. Consolidated Statements of Cash Flows, Continued


Supplemental Cash Flow Information:
Cash paid for interest	$	4,340		$	2,061		$	2,553
Non-cash Investing and Financing Activities:
Capitalized asset retirement obligation	$	(100	)	$	1,735		$	(17	)
(Decrease) increase in accrued capital expenditures	$	355		$	3,030		$	(780	)
Accounts receivable distributed to NSEC	$	—		$	(7,014	)	$	—
Accounts payable assumed by NSEC	$	—		$	(1,742	)	$	(172	)
Subordinated note issued to NSEC for oil and natural gas properties	$	—		$	25,000		$	—
Common units issued in connection with acquisitions	$	(46,239	)	$	(57,778	)	$	—
Acquisition of property and equipment by financing	$	7,580		$	—		$	—
Factoring payables assumed in connection with acquisitions	$	15,840		$	—		$	—
Debt assumed in connection with acquisitions	$	17,571		$	—		$	—

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

F-7

Table of Contents

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Nature of Business. We are a Delaware limited partnership formed in October 2012 to own and acquire oil and natural gas properties in the United States. We are engaged in the production of onshore oil and natural gas properties that extend across conventional resource reservoirs in east-central Oklahoma. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation. In addition, we are engaged in oilfield services through our oilfield services subsidiaries. Our oilfield services business provides wellsite services during the drilling and completion stages of a well, including full service blowout prevention installation, pressure testing services, including certain ancillary equipment necessary to perform such services, well testing and flowback services to companies in the oil and natural gas industry primarily in Oklahoma, Texas, New Mexico, Kansas, Pennsylvania, Ohio and West Virginia.

On February 13, 2013, the Partnership completed its initial public offering (the “Offering”) of 4,000,000 common units representing limited partner interests in the Partnership. From the proceeds of the Offering, the Partnership made a cash distribution of $15.8 million to NSEC as consideration (together with its issuance to NSEC of what then constituted approximately 50% of New Source Energy GP, LLC, which owns all of the Partnership general partner units, 777,500 common units, 2,205,000 subordinated units and a $25.0 million note payable) in exchange for the contribution by NSEC of the IPO Properties and certain commodity derivative contracts. Additionally, the Partnership assumed approximately $70.0 million of NSEC's indebtedness previously secured by the IPO Properties, and used a portion of the net proceeds from the Offering to repay in full this assumed debt at the closing of the Offering.

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

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

Principles of Consolidation. The consolidated financial statements include the accounts of the Partnership and its wholly owned and majority owned subsidiaries. Noncontrolling interest represents third-party ownership interest in a majority owned subsidiary of the Partnership and is included as a component of equity in the consolidated balance sheet and consolidated statement of unitholders' equity. All significant intercompany accounts and transactions have been eliminated in consolidation.

Reclassifications. Certain reclassifications have been made to the prior period financial statements to conform to the current period presentation. These reclassifications have no effect on the Partnership's previously reported results of operations or working capital.

Use of Estimates. The preparation of the Partnership’s consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities that exist at the date of the Partnership’s consolidated financial statements, as well as the reported amounts of revenue and expenses during the reporting periods. The Partnership’s consolidated financial statements are based on a number

F-8

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

of significant estimates, including oil, natural gas and NGL reserves, revenue and expense accruals, depreciation, depletion and amortization, fair value of derivative instruments and contingent consideration, the allocation of purchase price to the fair value of assets acquired and liabilities assumed, fair values of reporting units used in goodwill impairment testing, fair values of other intangible assets used in recording impairments and asset retirement obligations. Actual results could differ from those estimates.

Cash and Cash Equivalents. The Partnership considers all highly liquid investments (i.e., investments which, when purchased, have original maturities of three months or less) to be cash equivalents. Cash is held at financial institutions that are insured by the FDIC. At times, the balance may exceed the federally insured limits.

Accounts Receivable and Allowances. Accounts receivable include amounts for sales of oil, natural gas and NGL, as well as amounts due from customers for services performed. The Partnership grants credit to its customers in the ordinary course of business and generally does not require collateral. Customer balances are considered delinquent if unpaid 90 days following the invoice date, and credit privileges may be revoked if balances remain unpaid. Accounts receivable are reviewed and an estimate for losses is provided through an allowance for doubtful accounts when deemed appropriate. In evaluating the level of established reserves, we make judgments regarding our customers’ ability to make required payments, economic events and other factors. As the financial condition of customers changes, circumstances develop or additional information becomes available, adjustments to the allowance for doubtful accounts may be required. In the event we were to determine that a customer may not be able to make required payments, we would increase the allowance through a charge to income in the period in which that determination is made. Uncollectible accounts receivable are periodically charged against the allowance for doubtful accounts once final determination is made that they will not be collected.

Accounts receivable consist of the following as of December 31, 2014 and 2013 (in thousands):



	2014			2013
Oil, natural gas and NGL sales	$	6,710		$	8,417
Oil, natural gas and NGL sales - related parties	1,546			228
Oilfield services	30,668			3,964
	38,924			12,609
Less: allowance for doubtful accounts	(140		)	—
Total accounts receivable, net	$	38,784		$	12,609

Based on management’s assessment of credit history with customers having outstanding balances and current relationships with them, it has concluded that an allowance of $0.1 million was necessary as of December 31, 2014. No allowance for doubtful accounts was deemed necessary as of December 31, 2013. From time to time, the Partnership may factor its accounts receivable. As part of the factoring arrangement, certain receivables are pledged as collateral. See "Note 5 - Factoring Payable" for additional information regarding our factoring arrangements.

Inventory. Inventory is stated at the lower of cost or market value, determined on an average cost basis. Inventories consist of consumable materials used during the performance of services and are available for resale. The Partnership assesses the realizability of its inventories based on specific usage and future utility. A charge to cost of sales is taken when factors that would result in a need for reduction in valuation, such as excess or obsolete inventory, are determined. No allowance for obsolescence was deemed necessary as of December 31, 2014 or 2013.

Fair Value of Financial Instruments. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Additionally, GAAP requires the use of valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. The carrying amounts reflected in the balance sheet for cash and cash equivalents, accounts receivable, accounts payable, accrued liabilities, and factoring payable approximate the respective fair values due to the short maturities of those instruments. Other financial instruments consist of long-term obligations. The fair value of long-term obligations is estimated based on current interest rates offered to the Partnership for obligations with similar remaining maturities (Level 2). The recorded value of these financial instruments approximated fair value at December 31, 2014 and 2013. See "Note 7 - Fair Value Measurements" for further discussion of our fair value measurements.

Fair Value of Non-financial Assets and Liabilities. We also apply fair value accounting guidance to initially, or as events dictate, measure non-financial assets and liabilities such as those obtained through business acquisitions, property, plant and equipment and asset retirement obligations. These assets and liabilities are subject to fair value adjustments only in certain circumstances and are not subject to recurring revaluations. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two as considered appropriate based on the circumstances. Under the discounted cash

F-9

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil, natural gas, and NGL production or other applicable sales estimates, operational costs and a risk-adjusted discount rate. We may use the present value of estimated future cash inflows and/or outflows or third-party offers to value non-financial assets and liabilities when circumstances dictate determining fair value is necessary. Given the significance of the unobservable nature of a number of the inputs, these are considered Level 3 on the fair value hierarchy discussed in "Note 7 - Fair Value Measurements."

Derivative Financial Instruments. To manage risks related to fluctuations in prices attributable to expected oil, natural gas and NGL production, we enter into oil, natural gas and NGL derivative contracts. We recognize our derivative instruments as either assets or liabilities at fair value with changes in fair value recognized in earnings unless designated as a hedging instrument with specific hedge accounting criteria having been met. We have elected not to designate price risk management activities as accounting hedges under applicable accounting guidance, and, accordingly, account for our commodity derivative contracts at fair value with changes in fair value reported currently in earnings. We net derivative assets and liabilities whenever we have a legally enforceable master netting agreement with the counterparty to a derivative contract. The related cash flow impact of our derivative activities are reflected as cash flows from operating activities unless the derivative contract contains a significant financing element, in which case, cash settlements are classified as cash flows from financing activities in the consolidated statement of cash flows. See "Note 6 - Derivative Contracts" for further discussion of our derivatives.

Oil and Natural Gas Operations. We use the full cost method to account for our oil and natural gas properties. Under full cost accounting, all costs directly associated with the acquisition, exploration and development of oil, natural gas and NGL reserves are capitalized into a full cost pool. Capitalized costs are amortized using the unit-of-production method. Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.

Under the full cost method of accounting, total capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and impairment, less related deferred income taxes may not exceed an amount equal to the present value of future net revenues from proved reserves, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, plus estimated salvage value, less the related tax effects (the “ceiling limitation”). A ceiling limitation calculation is performed at the end of each quarter. If total capitalized costs, net of accumulated depreciation, depletion and impairment, less related deferred taxes are greater than the ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ equity in the period of occurrence and typically results in lower depreciation and depletion expense in future periods. Once incurred, a write-down is not reversible at a later date. The ceiling limitation calculation is prepared using the 12-month oil, natural gas, and NGL average price for the most recent 12 months as of the balance sheet date and as adjusted for basis or location differentials, held constant over the life of the reserves (“net wellhead prices”). If applicable, these net wellhead prices would be further adjusted to include the effects of any fixed price arrangements for the sale of oil, natural gas, and NGL. Derivative contracts that qualify and are designated as cash flow hedges are included in estimated future cash flows, although we have not designated any of our derivative contracts as cash flow hedges and have therefore not included our derivative contracts in estimating future cash flows.

When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas properties for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.

F-10

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

Property and Equipment. Property and equipment is recorded at cost, net of accumulated depreciation. The cost of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the year of disposal. The Partnership calculates depreciation expense using the straight-line method over the assets’ estimated useful lives, which are as follows:



	Estimated Useful Life (in years)
Vehicles and trailers	3	-	10
Machinery and equipment	3	-	20
Office equipment	3	-	7
Rental irons			10
Leasehold improvements (1)	3	-	10

_______________

(1) Leasehold improvements are depreciated on the straight-line basis over the remaining months of the applicable lease.

Expenditures for major additions and improvements are capitalized, while minor replacements, maintenance, and repairs that do not improve or extend the life of such assets, are charged to operations as incurred.

We make estimates and judgments about future undiscounted cash flows and fair values. Although our cash flow forecasts are based on assumptions that are consistent with our plans, there is a significant degree of judgment involved in determining the cash flows attributable to a long-lived asset over its estimated remaining useful life. Our estimates of anticipated cash flows could be reduced significantly in the future and as a result, the carrying amounts of our long-lived assets could be subject to impairment charges in the future.

Intangible Assets. As part of the acquisition of MCE in November 2013 and acquisitions of MidCentral Completion Services, LLC (“MCCS”), Erick Flowback Services LLC ("EFS") and Rod’s Production Services L.L.C. ("RPS") in June 2014, intangible assets for customer relationships and non-compete agreements were identified and recognized. Amortization for the customer relationship intangible assets was computed using an accelerated method over seven years similar to the expected cash flow pattern of the acquired customer relationships. Amortization for the non-compete agreement intangible asset was based on a straight-line approach over the agreement period. See "Note 8 - Goodwill and Intangible Assets" for additional discussion of our intangible assets and impairment assessment performed in the fourth quarter of 2014.

Goodwill. In conjunction with the acquisitions of MCE, MCCS, EFS and RPS, the Partnership recorded goodwill, which represents the consideration the Partnership paid in excess of the fair value of identifiable assets in the acquisitions. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of November 1 for MCE and April 1 for MCCS, EFS and RPS, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. See "Note 8 - Goodwill and Intangible Assets" for additional discussion of goodwill and impairment assessment performed in the fourth quarter of 2014.

Debt Issuance Costs. We amortize debt issuance costs related to our long-term debt as interest expense over the scheduled maturity period of the related debt. We include unamortized debt issuance costs in other assets in the consolidated balance sheet. Upon retirement of debt, any unamortized costs are written off and included in the determination of the gain or loss on extinguishment of debt.

Contingent Consideration. Contingent consideration, which represents earn out payments in connection with certain of the Partnership’s acquisitions, is recognized at fair value on the acquisition date and remeasured each reporting period with subsequent adjustments to fair value included in general and administrative expenses in the accompanying consolidated statements of operations. The Partnership estimates the fair value of contingent consideration liabilities based on certain performance milestones of the acquired companies or properties, and estimated probabilities of achievement, then discounts the liabilities to present value using the Partnership’s cost of debt. Contingent consideration is valued using significant inputs that are not observable in the

F-11

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

market which are defined as Level 3 inputs pursuant to fair value measurement accounting. The Partnership believes its estimates and assumptions are reasonable; however, there is significant judgment involved.

Changes in the fair value of contingent consideration liabilities may result from changes in discount periods, changes in the timing and amount of sales and/or other specific milestone estimates and changes in probability assumptions with respect to the likelihood of achieving the various earn out criteria. These changes could cause a material impact to, and volatility in our operating results. Earn out payments, if any, will be reflected in cash flows from financing activities and the changes in fair value are reflected in cash flows from operating activities in the consolidated statements of cash flows. See "Note 3 - Contingent Consideration" for additional discussion of our contingent consideration obligations.

Asset Retirement Obligations. We own oil and natural gas properties that require expenditures to plug, abandon and remediate wells at the end of their productive lives, in accordance with applicable federal and state laws. Liabilities for these asset retirement obligations are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired) at the estimated present value at the asset’s inception, with the offsetting increase to property cost. These property costs are depreciated on a unit-of-production basis within the full cost pool. The liability accretes each period until it is settled or the well is sold, at which time the liability is removed. Both the accretion and the depreciation are included in the consolidated statement of operations. We determine our asset retirement obligations by calculating the present value of estimated expenses related to the liability. Estimating future asset retirement obligations requires management to make estimates and judgments regarding timing, existence of a liability and what constitutes adequate restoration. Inherent in the present value calculation rates are the timing of settlement and changes in the legal, regulatory, environmental and political environments, which are subject to change. See "Note 13 - Asset Retirement Obligations" for further discussion of our asset retirement obligations.

Revenue Recognition. All revenue is recognized when persuasive evidence of an arrangement exists, the product or service has been provided, the amount is fixed or determinable and collectability is reasonably assured.

Oil, natural gas and NGL 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, natural gas, and NGL sales such that revenues are recognized based on the actual proceeds from the oil, natural gas, and NGL sold to purchasers. Oil, natural gas, and NGL 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, 2014 and 2013, there were no significant oil, natural gas, and NGL imbalances.

Pressure testing services are provided under master service agreements with our customers. Services are typically provided on a day rate or hourly basis. Jobs for these services are typically short-term in nature and range from a few hours to a few days. Revenue is recognized as the services are performed based upon a completed field ticket, which includes the charges for the services performed, mobilization of the equipment to the location and the personnel involved in such services or mobilization. Additional revenue is generated through the sale of consumable supplies that are incidental to the service being performed. The use of consumable supplies is reflected on completed field tickets and billed with the services, as discussed above.

Deferred Compensation Plans. In 2014, the Board of Directors of our general partner approved a 401(k) retirement plan for our employees. Under the plan, eligible employees may elect to defer a portion of their earnings up to the maximum allowed by regulations promulgated by the Internal Revenue Service (“IRS”). For the year ended December 31, 2014, the Company made matching contributions to the plan equal to 100% on the first 3% of employee deferred wages. Retirement plan expense for the years ended December 31, 2014 was approximately $0.3 million.

Income Taxes. Income taxes are reflected in these consolidated financial statements during the periods in which the IPO Properties were owned by a taxable entity. Since the Partnership is not a taxable entity, no income taxes have been provided for the periods following completion of the Offering. Upon the Partnership becoming a non-taxable entity, the Partnership recognized a tax benefit related to the change in tax status of approximately $12.1 million for the year ended December 31, 2013.

We are a limited partnership for federal and state income tax purposes, with the exception of the state of Texas, in which income tax liabilities and/or benefits of the Partnership are passed through to its unitholders. Limited partnerships are subject to Texas margin tax.

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Accounting Standards Codification (“ASC”) Topic 740, Income Taxes, which clarifies the accounting for uncertainties in income taxes recognized in the financial statements, provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, based on the technical merits. Income tax positions must meet a more-likely-than-not recognition threshold at the effective date to be recognized upon the adoption of ASC 740 and in subsequent periods. As of and for the years ended December 31, 2014 and 2013, the Partnership did not have any uncertain tax positions, and therefore no adjustments have been made to the financial statements. The tax years 2011 – 2013 remain open to examination for federal income tax purposes. MCES’ income tax returns for the period ended November 12, 2013 and the year ended December 31, 2012 remain subject to potential examination by major tax jurisdictions. Prior to 2012, all entities were single-member LLC’s and were disregarded for tax purposes.

Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership's book basis in its net assets exceeds the Partnership's net tax basis by $111.2 million at December 31, 2014.

Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Environmental expenditures are expensed or capitalized, as appropriate, depending on future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when an EA and/or remediation activities are probable and costs can be reasonably estimated. See "Note 15 - Commitments and Contingencies" for discussion of our commitments and contingencies.

Concentration of Risk. Our derivative transactions have been carried out in the over-the-counter market. The entry into derivative transactions in the over-the-counter market involves the risk that the counterparties may be unable to meet the financial terms of the transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating.

A default by the Partnership under its senior secured revolving credit facility (the “credit facility”) constitutes a default under its derivative contracts with its counterparty that is also a lender under the credit facility. We have master netting agreements with our derivative counterparties, which allow us to net our derivative assets and liabilities with the same counterparty. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts.

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

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

In February 2015, the FASB issued ASU 2015-02, Amendments to the Consolidation Analysis, which makes changes to both the variable interest model and the voting model, affecting all reporting entities involved with limited partnerships or similar entities, particularly industries such as the oil and gas, transportation and real estate sectors. In addition to reducing the number of consolidation models from four to two, the guidance simplifies and improves current guidance by placing more emphasis on

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risk of loss when determining a controlling financial interest and reducing the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity. The requirements of the guidance are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period, with early adoption permitted. We are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.

2. Acquisitions

The Partnership completed acquisitions during 2013 and 2014, as described below. Certain of the 2013 acquisitions increased the Partnership's portfolio of oil and natural gas properties. The acquisitions of MCE, EFS, RPS and MCCS established the Partnership's oilfield services segment. With the exception of the acquisition of oil and natural gas properties from Orion Exploration Partners, LLC, all of the 2013 acquisitions were with related parties. The acquisition of MCCS was the only acquisition in 2014 with related parties. See "Note 11 - Related Party Transactions."

The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy as described in "Note 7 - Fair Value Measurements." Fair value may be estimated using comparable market data, a discounted cash flow method, or another method as discussed below. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of applicable sales estimates, operational costs and a risk-adjusted discount rate. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. Fair value of MCCS' inventory acquired was determined based on a comparative sales approach. Fair value for intangible assets acquired was primarily determined using a discounted cash flow model or multi-period excess earnings model under the income approach, which factors in discount rates, probability factors and forecasts. The fair values of property, plant and equipment acquired were primarily based on a cost approach using an indirect cost methodology to determine replacement cost. The inputs, as noted above, used to determine fair value required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Carrying value for current assets and liabilities acquired is typically representative of fair value due to their short term nature.

2013 Acquisitions

March 2013 Acquisition. In March 2013, we acquired certain oil and natural gas properties located in the Golden Lane and Luther fields in Oklahoma from NSEC, Scintilla, and W.K. Chernicky, LLC, for an aggregate adjusted purchase price of approximately $28.0 million (the "March 2013 Acquisition"). As consideration, the Partnership issued 1,378,500 common units valued at $20.30 per unit.

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



Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	29,049
Other assets	754
Asset retirement obligations	(1,333		)
Other liabilities	(488		)
Total net assets	$	27,982

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May 2013 Acquisition. In May 2013, the Partnership completed an acquisition of certain oil and natural gas properties located in Oklahoma from NSEC for approximately $7.9 million, net of purchase price adjustments (the "May 2013 Acquisition").

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



Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	8,165
Asset retirement obligations	(19		)
Other liabilities	(254		)
Total net assets	$	7,892

July 2013 Acquisition. In July 2013, the Partnership completed an acquisition of a 10% working interest in certain oil and natural gas properties located in Oklahoma from Scintilla for approximately $4.9 million, net of purchase price adjustments (the "July 2013 Acquisition").

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



Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	4,888
Asset retirement obligations	(4		)
Other liabilities	(18		)
Total net assets	$	4,866

Orion Acquired Properties. In July 2013, the Partnership acquired certain oil and natural gas properties located in Oklahoma from Orion Exploration Partners, LLC for approximately $3.2 million, net of purchase price adjustments (the "Orion Acquired Properties").

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



Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	3,274
Asset retirement obligations	(24		)
Other liabilities	(20		)
Total net assets	$	3,230

Southern Dome Acquisition. In October 2013, the Partnership completed the acquisition of working interests in 25 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma (the "Southern Dome Acquisition") from Scintilla for total consideration of $14.5 million, net of purchase price adjustments.

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



Consideration:
Cash	$	4,260
Fair value of common units granted (1)	8,608
Contingent consideration (2)	1,600
Total fair value of consideration	$	14,468

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	15,190
Asset retirement obligations	(170		)
Other liabilities	(552		)
Total net assets	$	14,468

_______________


(1)	The fair value of the unit consideration was based upon 414,045 common units valued at $20.79 per unit (closing price on the date of the acquisition).


(2)	The Partnership agreed to provide additional consideration to Scintilla if average daily production attributable to the acquired working interests exceeds a specified average daily production during the specified period (the "Southern Dome Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the Southern Dome Contingent Consideration.

MCE Acquisition. In November 2013, the Partnership acquired 100% of the equity interests in MCE, other than Class B units that were retained by certain of the sellers as discussed further below (the "MCE Acquisition"). MidCentral Energy Services, LLC ("MCES"), a wholly owned subsidiary of MCE, operates an oilfield services business that offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region and in South Texas and West Texas, along with the rental of certain ancillary equipment necessary to perform such services.

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



Consideration:
Cash	$	3,781
Fair value of common units granted (1)	41,822
Common units granted to MCE employees (2)	2,259
Contingent consideration (3)	6,320
MCE Class B units granted (4)	16,589
Total fair value of consideration	$	70,771

_______________


(1)	The fair value of the unit consideration was based upon 1,847,265 common units valued at $22.64 per unit (closing price on the date of the acquisition).

(2)

The fair value of the unit consideration was based upon 99,768 common units valued at $22.64 per unit (closing price on the date of the acquisition). These common units were issued to certain employees of MCE under the Partnership’s long-term incentive plan, primarily for service prior to the acquisition. Any forfeited common units do not revert to the Partnership, but would be distributed to the former owners of MCE.

(3)

The owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCES for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $120.0 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCE Contingent Consideration.

(4)

Certain former owners of MCE retained Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds in increasing amounts. See "Note 9 - Equity" for additional discussion of these incentive distributions. The Class B units were valued at $16.6 million through the use of a Monte Carlo simulation. Includes an adjustment of $2.6 million made during the fourth quarter of 2014 to the initial value of these units.

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



Fair value of assets acquired and liabilities assumed:
Cash	$	1,522
Accounts receivable	3,365
Other current assets	954
Property and equipment	7,923
Intangible asset (1)	36,772
Goodwill (2) (3) (4)	26,678
Other assets	19
Total assets acquired	77,233
Accounts payable and accrued liabilities (3)	(2,448		)
Factoring payable	(1,679		)
Long-term debt	(2,335		)
Total liabilities assumed	(6,462		)
Net assets acquired	$	70,771

_______________


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

(2)

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workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business. Goodwill has been allocated to the oilfield services segment.


(3)	Includes purchase price allocation adjustment of $0.1 million made during the third quarter of 2014 based on additional information received on accounts payable assumed.


(4)	Includes purchase price allocation adjustment of $2.6 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.

Since the Chairman and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos, through his control over the Partnership’s general partner, controls the Partnership and also owned 36% of the equity interest in MCE, the MCE Acquisition was accounted for as a business combination achieved in stages. The Partnership initially recorded the 36% equity interest in MCE acquired from Mr. Kos at his equity method carrying basis, which was $1.8 million as of November 12, 2013. The Partnership remeasured the 36% interest to determine the acquisition-date fair value and recognized a corresponding gain of $22.7 million on investment in acquired business.

The revenues and operating income included in the accompanying consolidated statements of operations for the year ended December 31, 2013 generated by the March 2013 Acquisition, the Southern Dome Acquisition, and the MCE Acquisition are shown in the table below. Operating income attributable to the March 2013 Acquisition and the Southern Dome Acquisition represents the excess of revenue over direct operating expenses and does not reflect certain expenses, such as general and administrative; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. Direct operating expenses for the March 2013 Acquisition and the Southern Dome Acquisition include lease operating expenses and production taxes.



	Year Ended December 31, 2013
	(in thousands)
Revenue	$	11,465
Excess of revenues over direct operating expenses	$	6,533

Acquisition expense related to the acquisitions as of December 31, 2013 of approximately $2.1 million were included in general and administrative expenses in the accompanying consolidated statements of operations for the year ended December 31, 2013.

2014 Acquisitions

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

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



Consideration:
Cash	$	5,503
Fair value of common units granted (1)	11,621
Contingent consideration (2)	—
Total fair value of consideration	$	17,124

Fair value of assets acquired and liabilities assumed:
Proved oil and natural gas properties	$	17,306
Asset retirement obligations	(182		)
Total net assets	$	17,124

_______________


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

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(2)	The Partnership agreed to provide additional consideration to CEU if average daily production attributable to the acquired working interests exceeds a specified average daily production during a specified period (the "CEU Contingent Consideration"). See "Note 3 - Contingent Consideration" for additional discussion of the CEU Contingent Consideration.

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

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



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

________________


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

(2)

The owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, subject to a $4.5 million cap ("MCCS Contingent Consideration"). The MCCS Contingent Consideration was valued at $4.1 million at the acquisition date through the use of a Monte Carlo simulation. See "Note 3 - Contingent Consideration" for additional discussion of the MCCS Contingent Consideration.

(3)

As a condition of the acquisition agreement, MCCS was contributed to MCE by the Partnership, which increased the value of the noncontrolling interest held by MCE's Class B unitholders. The increase in the value of the noncontrolling interest that resulted from this is part of the total consideration paid for the MCCS Acquisition and was valued at the acquisition date through the use of a Monte Carlo simulation. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.

The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):



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

__________


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


(2)	Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of

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MCCS includes any intangible assets that do not qualify for separate recognition, such as the MCCS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCCS's business. Goodwill has been allocated to the oilfield services segment. Includes purchase price allocation adjustment of $0.7 million made during the fourth quarter of 2014 based on an adjustment to the initial value of the Class B units.

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

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

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



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

_______________


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

(2)

The fair value of the unit consideration was based upon 30,867 common units valued at $23.45 per unit (closing price on the date of the transaction). These units were issued to satisfy the settlement of phantom units granted to EFS employees with no service requirement. An additional 401,171 common units, which were issued and are held in escrow to satisfy the future settlement of phantom units granted to EFS and RPS employees in conjunction with the Services Acquisition, are excluded from consideration based on the future service requirement for vesting. See "Note 9 - Equity" for additional discussion of phantom units.

(3)

The former owners of EFS and RPS are entitled to receive additional consideration in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments ("EFS/RPS Contingent Consideration"). The EFS/RPS Contingent Consideration was valued at $22.0 million through the use of a probability analysis. See "Note 3 - Contingent Consideration" for additional discussion of the EFS/RPS Contingent Consideration. Includes a purchase price allocation adjustment made during the third quarter of 2014 for approximately $4.8 million to increase the value of the contingent consideration based on additional information made available.

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The following table summarizes the assets acquired and the liabilities assumed as of the acquisition date at estimated fair value (in thousands):



Fair value of assets acquired and liabilities assumed:
Cash	$	1,668
Accounts receivable (1)	22,674
Other current assets (2)	620
Property and equipment (2)	43,853
Intangible assets (3)	68,700
Goodwill (4)	14,224
Total assets acquired	151,739
Accounts payable and accrued liabilities (1) (2)	(5,937		)
Factoring payable	(15,840		)
Long-term debt	(16,800		)
Total liabilities assumed	(38,577		)
Net assets acquired	$	113,162

_______________


(1)	Includes purchase price allocation adjustments resulting in an increase totaling $1.2 million during the fourth quarter, based on additional information received primarily on accounts receivable and accrued liabilities.


(2)	Includes purchase price allocation adjustments resulting in an increase totaling $1.1 million during the third quarter of 2014, based on additional information received primarily on other current assets and property and equipment acquired.

(3)

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

(4)

Goodwill is calculated as the excess of the consideration transferred over the fair value of net assets recognized and represents the estimated future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Such goodwill is not deductible for tax purposes. Specifically, the goodwill recorded as part of the Services Acquisition includes any intangible assets that do not qualify for separate recognition, such as the EFS and RPS trained, skilled and assembled workforce, along with the expected synergies from leveraging the customer relationships. Goodwill has been allocated to the oilfield services segment. Purchase price allocation adjustments increased the amount assigned to goodwill by approximately $3.7 million in the third quarter of 2014, primarily as a result of an increase to the value of the contingent consideration based on additional information made available. Additional purchase price allocation adjustments in the fourth quarter of 2014 decreased the amount assigned to goodwill by approximately $1.2 million based on additional information received on accounts receivable and accrued liabilities.

Pro forma financial information. The following unaudited pro forma combined results of operations are presented for the year ended December 31, 2014 as though the Partnership completed the CEU Acquisition and the Services Acquisition (collectively, the "2014 Material Acquisitions") as of January 1, 2013. The pro forma combined results of operations for the year ended December 31, 2014 have been prepared by adjusting the historical results of the Partnership to include the historical results of the 2014 Material Acquisitions through the dates of acquisition and estimates of the effect of these transactions on the combined results. In addition, pro forma adjustments have been made assuming the units issued as consideration for these acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund an acquisition, had been outstanding since January 1, 2013. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

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	Year Ended December 31, 2014
	(in thousands, except per unit amounts)
Revenue	$	227,564
Net loss attributable to New Source Energy Partners L.P. (1)	$	(32,531	)
Net loss per common unit (1):
Basic	$	(1.61	)
Diluted	$	(1.61	)

_______________


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

The amounts of revenues and operating loss included in the accompanying consolidated statements of operations for the year ended December 31, 2014 generated by the 2014 Material Acquisitions are shown in the table below. The operating income attributable to the CEU Acquisition represents the excess of revenue over direct operating expenses and does not reflect certain expenses, such as general and administrative; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. Direct operating expenses include lease operating expenses and production taxes for the CEU Acquisition.



	Year Ended December 31, 2014
	(in thousands)
Revenue	$	69,167
Operating loss	$	(2,452	)

Acquisition expenses for the 2014 Material Acquisitions of $3.6 million were included in general and administrative expenses in the accompanying consolidated statements of operations for the year ended December 31, 2014.

The following unaudited pro forma combined results of operations are presented for the year ended December 31, 2013 as though the Partnership completed the March 2013 Acquisition, the Southern Dome Acquisition and the MCE Acquisition (collectively, the "2013 Material Acquisitions") as of January 1, 2012, which was the beginning of the earliest period presented at the time of the acquisition, and completed the 2014 Material Acquisitions as of January 1, 2013. The pro forma combined results of operations for the year ended December 31, 2013 have been prepared by adjusting the historical results of the Partnership to include the historical results of these acquisitions through the date of acquisition and estimates of the effect of the 2013 Material Acquisitions and the 2014 Material Acquisitions on the combined results. In addition, pro forma adjustments have been made for the interest that would have been incurred for financing the cash portion of the consideration of the 2013 Material Acquisitions with the Partnership's senior secured revolving credit facility and assume the units issued as consideration for the 2013 Material Acquisitions had been outstanding since January 1, 2012 and the units issued as consideration for the 2014 Material Acquisitions and a portion of the units issued in the April 2014 equity offering, the proceeds from which were used to fund an acquisition, had been outstanding since January 1, 2013.



		Year Ended December 31, 2013
		Year Ended December 31, 2013
	(in thousands, except per unit amounts)
Revenue		$	188,232
Net loss attributable to New Source Energy Partners L.P. (1)		$	(15,931	)
Net loss per common unit (1):
Basic		$	(0.98	)
Diluted		$	(0.98	)

_______________


(1)	Includes $1.6 million of the Partnership's acquisition costs related to the 2014 Material Acquisitions in the year ended December 31, 2013.

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3. Contingent Consideration

The contingent consideration provided for in certain of our acquisitions represents additional consideration. The fair value of such contingent consideration is estimated using various inputs, including the probability that targets for additional payout will be met, as described below. As the significant inputs to determine fair value of the contingent consideration represent significant unobservable inputs, they are classified as Level 3 under the fair value hierarchy described in "Note 7 - Fair Value Measurements."

A reconciliation of the beginning and ending balances of acquisition-related contingent consideration for the years ended December 31, 2014 and 2013 is as follows (in thousands):



	Year Ended December 31,
	2014			2013
Contingent consideration, beginning balance	$	6,320		$	—
Acquisition date fair value of contingent consideration - Southern Dome	—			1,600
Acquisition date fair value of contingent consideration - MCE Acquisition	—			6,320
Acquisition date fair value of contingent consideration - CEU Acquisition	—			—
Acquisition date fair value of contingent consideration - MCCS Acquisition	4,057			—
Acquisition date fair value of contingent consideration - Services Acquisition	21,984			—
Change in fair value of contingent consideration	(9,031		)	(1,600		)
Settlement of contingent consideration	—			—
Contingent consideration, ending balance	23,330			6,320
Less: current portion of contingent consideration	11,572			—
Less: offsetting receivable due from former owners	957			—
Contingent consideration, long-term	$	10,801		$	6,320

Southern Dome Contingent Consideration. In conjunction with the Southern Dome Acquisition, the Partnership agreed to provide additional consideration to Scintilla if the average daily production attributable to the acquired properties for the nine months ended September 30, 2014 exceeded 383.5 Boe. The contingent consideration was determined to have a fair value of $1.6 million at the acquisition date and was included in the consideration for the Southern Dome Acquisition. The Partnership estimated the fair value as of December 31, 2013 at $0. As detailed in the acquisition agreement, the additional consideration was calculated as the value of average daily production for the nine months ended September 30, 2014 less (i) the asset value, (ii) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (iii) revenue attributable to any wells located in a specified project area that were not producing in paying quantities as of the effective date of the acquisition. Any change to the fair value of the contingent consideration was adjusted through earnings due to the factors impacting the ultimate payout. Based on actual production levels for the nine months ended September 30, 2014, no additional consideration is due to Scintilla.

MCE Contingent Consideration. The former owners of MCE are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE, excluding EFS, RPS and MCCS, for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $120.0 million cap. The contingent consideration was valued at $6.3 million at the acquisition date and was included in the consideration for the MCE Acquisition. The Partnership estimated fair value of the MCE Contingent Consideration was approximately $6.3 million at December 31, 2013, which is presented as contingent consideration payable in the accompanying consolidated balance sheets. Any change to the fair value of the contingent consideration is adjusted through earnings. Based on current projections for MCE, the MCE Contingent Consideration was deemed to have no value as of December 31, 2014. The decrease in fair value of $6.3 million is included in the accompanying consolidated statements of operations for the year ended December 31, 2014.

CEU Contingent Consideration. In conjunction with the CEU Acquisition, the Partnership agreed to provide additional consideration to CEU if the average daily production attributable to the acquired working interest for the nine months ended September 30, 2014 exceeded 566.0 Boe. The CEU Contingent Consideration was determined to have no value at the acquisition date. As detailed in the acquisition agreement, the additional consideration was calculated as the acquisition value of the production increase less (i) capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells located in a specified project area that were not producing

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

in paying quantities as of the effective date of the acquisition. Based on actual production levels for the nine months ended September 30, 2014, no additional consideration is due to CEU.

MCCS Contingent Consideration. The former owners of MCCS are entitled to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCCS for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $4.5 million cap. The contingent consideration was valued at $4.1 million at the acquisition date and was included in the consideration for the MCCS Acquisition. Any changes to the fair value of the contingent consideration will be adjusted through earnings. Based on current projections for MCCS, the MCCS Contingent Consideration was deemed to have no value as of December 31, 2014. The decrease in fair value of $4.1 million is included in the accompanying consolidated statements of operations for the year ended December 31, 2014.

EFS/RPS Contingent Consideration. The former owners of EFS and RPS are entitled to receive additional consideration in the form of cash and common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of EFS and RPS for the year ended December 31, 2014, less certain adjustments. The terms of the contribution agreement provide that the additional consideration is to be paid approximately 50% in cash and approximately 50% in common units, consistent with the initial consideration for the Services Acquisition. However, the former owners can elect to receive a larger portion of the payout in common units. The contingent consideration was valued at $22.0 million as of the acquisition date and was included in the consideration for the Services Acquisition. The fair value of the contingent consideration was $23.3 million as of December 31, 2014. The increase in fair value of approximately $1.3 million was adjusted through earnings and is included in the accompanying consolidated statements of operations for the year ended December 31, 2014. In March 2015, we entered into an agreement with the former owners that allows for the payment of the cash portion of the contingent consideration to be extended to May 2016. As a result, this portion of the contingent consideration has been reflected as long-term in the accompanying consolidated balance sheet as of December 31, 2014. Additionally, a receivable of approximately $1.0 million due from the former owners has been offset against the contingent consideration obligation.

4. Debt

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



	December 31, 2014		December 31, 2013
Credit facility	$	83,000	$	78,500
Notes payable	20,424		2,233
Line of credit	3,619		—
Total debt	107,043		80,733
Less: current maturities of long-term debt	11,825		719
Long-term debt	$	95,218	$	80,014

Senior Secured Revolving Credit Facility

The Partnership has a senior secured revolving credit facility that is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below, (the "credit facility"). As of December 31, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than 2.5 to 1.0; (ii) a ratio of total debt to EBITDA of not more than 3.5 to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The financial covenants are calculated based on the results of the Partnership, excluding its subsidiaries. The obligations under the credit facility are secured by substantially all of the Partnership's oil and natural gas properties and other assets, excluding assets of all subsidiaries. The credit facility matures in February 2017.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

(ii) borrowing base utilization under the credit facility does not exceed 90%. As of December 31, 2014, the Partnership was in compliance with all covenants under the credit facility.

Borrowings under the credit facility are limited to a borrowing base, the amount of which is dependent on estimated oil, natural gas and NGL reserves, which factor in oil, natural gas and NGL prices, respectively. The borrowing base is subject to a semi-annual redetermination. The borrowing base was lowered in November 2014 to $90.0 million from $102.5 million. As of December 31, 2014, we had $83.0 million in outstanding borrowings with $7.0 million of available borrowing capacity and no available borrowing capacity before restriction on distribution occurs. In January and February 2015, the Partnership repaid $2.0 million in outstanding borrowings under the credit facility, which resulted in $81.0 million outstanding with no restrictions on our ability to pay distributions in February 2015. Based on our reserve estimates and using forward commodity prices, we anticipate a reduction to our borrowing base on our credit facility at the redetermination in April 2015. The precise amount of the reduction is not known at this time but the decrease could range from approximately $20 million to $30 million. Under the credit agreement, we would have approximately three months from the date of notification of a borrowing base reduction to pay any amounts outstanding in excess of the new borrowing base. Based on projected market conditions and lower commodity prices, we currently expect that we will not be in compliance with our current ratio covenant in certain future periods. We expect to successfully execute certain contemplated financing options to enable us to reduce the credit facility borrowings and comply with this covenant during 2015.

Notes Payable

The Partnership has financing notes with various lending institutions for certain property and equipment through MCES. These notes range from 12-60 months in duration with maturity dates from August 2015 through March 2019 and carry variable interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets of MCES and are secured by such assets. The Partnership had $7.6 million outstanding under the MCES notes payable as of December 31, 2014.

The EFS term loan agreement contains various covenants and restrictive provisions that, among other things, limit the ability of EFS and RPS to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments; make loans to the Partnership; and dispose of assets. Additionally, beginning October 1, 2014, EFS and RPS must comply with certain financial covenants, including maintaining (i) a fixed charge ratio of not less than 1.25 to 1.0 (ii) a leverage ratio of not greater than 1.5 to 1.0, and (iii) a working capital and cash balance of at least $4.0 million, in each case as more fully described in the loan agreement. As of December 31, 2014, EFS and RPS were in compliance with the covenants under the term loan agreement.

On March 13, 2015, we refinanced the EFS term loans to extend the maturity date from June 26, 2015 to March 13, 2018, which reduced the monthly payment, the reserve account requirement and the minimum working capital and cash balance covenant requirements. All other covenants and restrictions remain the same. As a result of this extension, the portion of principal now due January 1, 2016 or after of $8.3 million was classified on the accompanying consolidated balance sheet as long-term debt.

Line of Credit

In February 2014, MCES entered into a loan agreement for a revolving line of credit of up to $4.0 million, based on a borrowing base of $4.0 million related to MCES' accounts receivable. Interest only payments are due monthly on the line of credit which was originally set to mature in February 2015, but was extended to mature in May 2015. The line of credit replaced MCES' factoring

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

payable agreement described in "Note 5 - Factoring Payable." Interest on the line of credit accrues at the Bank of Oklahoma Financial Corporation National Prime Rate, which was 4.0% at December 31, 2014. The line of credit is secured by accounts receivable, inventory, chattel paper, and general intangibles of MCES. Based on the outstanding balance of $3.6 million, there was $0.4 million of available borrowing capacity at December 31, 2014.

The line of credit contains a covenant requiring a debt service coverage ratio, as defined in agreement, of not less than 1.25 to 1.0. As of December 31, 2014, MCES was in compliance with this covenant under the line of credit.

Debt Maturity

The following is a schedule by years of minimum principal payments for debt as of December 31, 2014 (in thousands):



Year ended December 31,	Amount (1)
2015	$	11,825
2016	7,185
2017 (2)	87,809
2018	219
2019	5
Total	$	107,043

_______________


(1)	Reflects refinancing of term loan agreement in March 2015.


(2)	Includes credit facility borrowings of $83.0 million maturing in February 2017.

5. Factoring Payable

The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of MCES. At December 31, 2013, the outstanding balance was $1.9 million. The outstanding balance was paid and the agreement was terminated in February 2014 when MCES established its line of credit. See "Note 4 - Debt" for discussion of MCES' line of credit.

6. Derivative Contracts

Due to the volatility of commodity prices, the Partnership periodically enters into derivative contracts to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations for a portion of its oil, natural gas and NGL production. While the use of derivative contracts limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and NGL, it also reduces the Partnership’s potential exposure to adverse price movements. The Partnership’s derivative contracts apply to only a portion of its expected production, provide only partial price protection against declines in market prices and limit the Partnership’s potential gains from future increases in market prices. Changes in the derivatives' fair values are recognized in earnings since the Partnership has elected not to designate its derivative contracts as hedges for accounting purposes.

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At December 31, 2014, the Partnership's derivative contracts consisted of collars, put options, and fixed price swaps, as described below:



Collars	The instrument contains a fixed floor price (long put option) and ceiling price (short call option), where the purchase price of the put option equals the sales price of the call option. At settlement, if the market price exceeds the ceiling price, the Partnership pays the difference between the market price and the ceiling price. If the market price is less than the fixed floor price, the Partnership receives the difference between the fixed floor price and the market price. If the market price is between the ceiling and the fixed floor price, no payments are due from either party.

Collars - three way	Three-way collars have two fixed floor prices (a purchased put and a sold put) and a fixed ceiling price (call). The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the New York Mercantile Exchange plus the difference between the purchased put strike price and the sold put strike price. The call establishes a maximum price (ceiling) the Partnership will receive for the volumes under the contract.

Put options	The Partnership periodically buys put options. At the time of settlement, if market prices are below the fixed price of the put option, the Partnership is entitled to the difference between the put option and the fixed price.

Fixed price swaps	The Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume.

The following tables present our derivative instruments outstanding as of December 31, 2014:



Oil collars	Volumes (Bbls)	Floor Price		Ceiling Price
2015	42,649	$	80.00	$	93.25



Oil collars - three way	Volumes (Bbls)	Sold Put		Purchased Put		Ceiling Price
2015	36,500	$	77.50	$	92.50	$	102.60



Natural gas collars	Volumes (MMBtu)	Floor Price		Ceiling Price
2015	1,362,382	$	4.00	$	4.32



Natural gas put options	Volumes (MMBtu)	Floor Price
2015	798,853	$	3.50
2016	930,468	$	3.50



Oil fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	39,411	$	88.90
2016	36,658	$	86.00



Natural gas fixed price swaps	Volumes (MMBtu)	Weighted Average Fixed Price
2015	800,573	$	4.25
2016	629,301	$	4.37

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED



NGL fixed price swaps	Volumes (Bbls)	Weighted Average Fixed Price
2015	84,793	$	75.18

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

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



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

Liabilities:
Commodity derivatives - current liabilities	$	61	$	(61	)	$	—
Commodity derivatives - long-term liabilities	—		—			—
Total	$	61	$	(61	)	$	—



December 31, 2013	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset			Net Amounts Presented
Assets:
Commodity derivatives - current assets	$	1,342	$	(1,212	)	$	130
Commodity derivatives - long-term assets	1,638		(978		)	660
Total	$	2,980	$	(2,190	)	$	790

Liabilities:
Commodity derivatives - current liabilities	$	4,379	$	(1,212	)	$	3,167
Commodity derivatives - long-term liabilities	1,015		(978		)	37
Total	$	5,394	$	(2,190	)	$	3,204

See "Note 7 - Fair Value Measurements" for additional information on the fair value measurement of the Partnership's derivative contracts.

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The following table presents gain (loss) on our derivative contracts as included in the accompanying consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 (in thousands):



	Year Ended December 31,
	2014		2013			2012
Total gain (loss) on derivative contracts, net (1)	$	10,707	$	(5,548	)	$	7,057

_______________


(1)	Included in gain (loss) on derivative contracts for the years ended December 31, 2014, 2013 and 2012 are net cash (payments) receipts upon contract settlement of $(1.8) million, $(1.9) million and $6.0 million, respectively.

7. Fair Value Measurements

We measure and report certain assets and liabilities at fair value and classify and disclose our fair value measurements based on the levels of the fair value hierarchy, as described below:

Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity).

Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership's assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

Level 2 Fair Value Measurements

Derivative contracts. Beginning in the second quarter of 2014, the fair values of our commodity collars, put options and fixed price swaps are based upon inputs that are either readily available in the public market, such as oil, natural gas, and NGL futures prices, volatility factors and discount rates, or can be corroborated from active markets. The Partnership estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, relying in part upon the assistance of third-party pricing experts, the forward curves as of the date of the estimate. The Partnership validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. The Partnership estimates the option value of puts and calls combined into hedges, market prices, contract parameters and discount rates based on published LIBOR rates.

Level 3 Fair Value Measurements

Derivative contracts. The fair values of our natural gas collars, natural gas and NGL put options and NGL fixed price swaps at December 31, 2013 and March 31, 2014 were based upon quotes obtained from counterparties to the derivative contracts. These values were reviewed internally for reasonableness. The significant unobservable inputs used in the fair value measurement of our natural gas and NGL put options and NGL fixed price swaps were the estimated probability of exercise and the estimate of NGL futures prices. Significant increases (decreases) in the probability of exercise and NGL futures prices could result in a significantly higher (lower) fair value measurement.

Contingent consideration. As discussed in "Note 3 - Contingent Consideration," the Partnership has agreed to pay additional consideration on the MCE Acquisition, the MCCS Acquisition and the Services Acquisition. The fair value of the contingent consideration resulting from these acquisitions is based on the present value of estimated future payments, using various inputs, including forecasted EBITDA metrics and the probability that targets for additional payout will be met. Significant increases (decreases) in the probability of meeting target payout levels could result in a significantly higher (lower) fair value measurement.

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



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



December 31, 2013	Fair Value Measurements
Description	Active Markets for Identical Assets (Level 1)		Observable Inputs (Level 2)			Unobservable Inputs (Level 3)			Total Carrying Value
Oil collars	$	—	$	(57	)	$	—		$	(57	)
Natural gas collars	—		—			(9		)	(9		)
Oil put options	—		28			—			28
Natural gas and NGL put options	—		—			403			403
Oil and natural gas fixed price swaps	—		132			—			132
NGL fixed price swaps	—		—			(2,911		)	(2,911		)
Contingent consideration	—		—			(6,320		)	(6,320		)
Total	$	—	$	103		$	(8,837	)	$	(8,734	)

The following table sets forth a reconciliation of our derivative contracts measured at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2014, 2013 and 2012 (in thousands):



	Year Ended December 31,
	2014			2013			2012
Beginning balance	$	(2,517	)	$	(112	)	$	(1,198	)
(Loss) gain on derivative contracts	(2,432		)	(4,075		)	7,051
Transfers out (1)	2,843			—			—
Cash paid upon settlement	2,106			1,670			(5,965		)
Ending balance	$	—		$	(2,517	)	$	(112	)
Unrealized losses included in earnings relating to derivatives held at period end	$	—		$	(2,446	)	$	(112	)

_______________

(1)

Fair values related to the Company’s natural gas collars, natural gas and NGL put options and NGL fixed price swaps were transferred from Level 3 to Level 2 in the second quarter of 2014 due to enhancements to the Company’s internal valuation process, including the use of observable inputs to assess the fair value. During the year ended December 31, 2013, the Company did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements. The Company’s policy is to recognize transfers in and/or out of fair value hierarchy levels as of the beginning of the quarterly reporting period in which the event or change in circumstances causing the transfer occurred.

See "Note 6 - Derivative Contracts" for additional discussion of our derivative contracts. See "Note 3 - Contingent Consideration" for a reconciliation of activity for contingent consideration during the years ended December 31, 2014 and 2013.

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Fair Value of Financial Instruments

Credit Facility. The carrying amount of the credit facility of $83.0 million and $78.5 million as of December 31, 2014 and December 31, 2013, respectively, approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings.

Notes Payable. The carrying value of our notes payable of $20.4 million and $2.2 million at December 31, 2014 and December 31, 2013 approximated fair value based on rates applicable to similar instruments.

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

Fair Value on a Non-Recurring Basis

The Partnership performs valuations on a non-recurring basis primarily as it relates to the consideration, assets acquired, and liabilities assumed related to acquisitions and impairments of goodwill and intangible assets. See "Note 2 - Acquisitions" and "Note 8 - Goodwill and Intangible Assets" for discussion of these valuations.

8. Goodwill and Intangible Assets

Goodwill

Goodwill represents the estimated future economic benefits arising from other assets acquired in business combinations that could not be individually identified and separately recognized. See "Note 2 - Acquisitions" for discussion of our business acquisitions. Goodwill has been allocated to reporting units within the oilfield services segment and is not deductible for tax purposes. In connection with the MCE Acquisition in November 2013, the Partnership recorded $24.0 million of goodwill, which represents the balance at December 31, 2013. A reconciliation of the aggregate carry amount of goodwill for the period from December 31, 2013 to December 31, 2014 is as follows (in thousands):



Goodwill at December 31, 2013	$	23,974
Additions:
MCCS Acquisition	4,060
Services Acquisition	11,664
Change due to purchase price allocation adjustments (1)	4,585
Impairment	(34,968		)
Goodwill at December 31, 2014	$	9,315

_______________

(1)

Includes adjustments totaling $3.8 million during the third quarter of 2014 as a result of purchase price allocation adjustments of $0.1 million and $3.7 million on the MCE Acquisition and Services Acquisition, respectively. Includes adjustments totaling $1.7 million during the fourth quarter of 2014 as a result of purchase price allocation adjustments of $2.6 million, $(0.7) million and $(0.2) million on the MCE Acquisition, MCCS Acquisition and Services Acquisition, respectively. See "Note 2 - Acquisitions" for discussion of the purchase price allocation adjustments.

In the fourth quarter of 2014, the Partnership deemed the significant decline in commodity prices and the related impact or estimated impact to our oilfield services business to be a triggering event for the purpose of evaluating goodwill. As such, impairment tests were performed as of December 31, 2014. Primarily as a result of a decrease in projected revenue of the respective reporting units, which is a significant component in determining the fair value of the reporting units, the carrying value of all reporting units exceeded their fair value. We performed step two of the impairment test to determine the amount of goodwill that was impaired. The excess of the carrying amount of the reporting units' goodwill over the implied fair value of the goodwill, approximately $35.0 million, was recorded as impairment and included in the accompanying consolidated statements of operations for the year ended December 31, 2014.

In order to estimate the fair value of the oilfield services reporting units (which is consistent with the entities acquired), we used the cost approach to value MCE and MCCS and a combination of the income approach and the market approach to value EFS and RPS. In order to validate the reasonableness of the estimated fair values obtained for the reporting units, a reconciliation of fair value to market capitalization was performed for each unit on a standalone basis. A control premium, derived from market transaction data, was used in this reconciliation to ensure that fair values were reasonably stated in conjunction with the Partnership’s

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total capitalization. These fair value estimates were then compared to the carrying value of the reporting units. The fair values of MCES and MCCS exceeded their carrying values such that after computing the implied fair value of each reporting unit's goodwill, the goodwill was fully impaired. The implied fair values of EFS and RPS resulted in a partial impairment of each reporting unit's goodwill. A significant amount of judgment was involved in performing these evaluations since the results are based on estimated future events.

Intangible Assets

Intangible assets were identified in certain of the acquisitions during 2013 and 2014. See "Note 2 - Acquisitions" for discussion of our business acquisitions. Intangible assets are amortized over the expected cash flow period for customer relationships and over the agreement period, or three years, for the non-compete agreements. Amortization expense for the years ended December 31, 2014 and 2013 was $25.0 million and $1.8 million, respectively. There was no amortization expense for the year ended December 31, 2012.

The Partnership's intangible assets at December 31, 2014 and December 31, 2013 consist of the following (in thousands):



	December 31, 2014		December 31, 2013
Customer relationships - MCE Acquisition	$	36,772	$	36,772
Customer relationships - Services Acquisition	64,200		—
Non-compete agreements - Services Acquisition	4,500		—
Customer relationships - MCCS Acquisition	1,700		—
Total intangible assets	107,172		36,772
Less: accumulated amortization	26,764		1,763
Impairment	24,031		—
Intangible assets, net	$	56,377	$	35,009

In the fourth quarter of 2014, the Partnership deemed the significant decline in commodity prices and the related impact or estimated impact to our oilfield services business to be a triggering event for the purpose of evaluating its intangible assets for impairment. Accordingly, impairment tests were performed by calculating the estimated future cash flows to be generated by the respective revenue generating asset groups. The undiscounted future cash flows were in excess of the respective revenue generating asset groups' carrying value for the intangible assets from the Services Acquisition; therefore, no impairment of these intangible assets was indicated as of December 31, 2014. For the customer relationships for MCE and MCCS, the undiscounted future cash flows were less than the respective revenue generating asset group's carrying value. Based on the discounted cash flows of the asset group, a full impairment of these intangible assets, or approximately $24.0 million, was recorded and is included in the accompanying consolidated statements of operations for the year ended December 31, 2014.

The amortization of customer relationships reflects a pattern in which the economic benefits of the assets will be consumed or used up. Amortization was estimated by using an accelerated method over seven years similar to the expected cash flow pattern of the acquired customer relationships, estimated for each of the five succeeding years ending December 31, as follows (in thousands):



	Total
2015	$	19,164
2016	12,743
2017	7,976
2018	4,767
2019	3,211
Thereafter	4,766
	$	52,627

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9. Equity

Units

Initial Public Offering. In February 2013, the Partnership completed its Offering of 4,000,000 common units representing limited partner interests in the Partnership at a price to the public of $20.00 per common unit. In March 2013, 250,000 common units were issued from the partial exercise of the underwriters' overallotment option. Total proceeds from the Offering and exercise of the overallotment option, net of offering costs and underwriter discounts, were $76.6 million. In exchange for the contribution by NSEC of the IPO Properties and certain commodity derivative contracts, the Partnership distributed to NSEC $15.8 million and issued to NSEC 777,500 common units, 2,205,000 subordinated units, a $25.0 million note payable and approximately 50.0% of equity interests in our general partner, which owns all of the Partnership general partner units.

Private Placement. In December 2013, we completed a private placement of 465,000 common units pursuant to a common unit purchase agreement, resulting in approximately $9.8 million in proceeds to us. The proceeds from this offering were used for general corporate purposes.

Issuance for Acquisitions. In 2013, we issued 3,739,578 common units to satisfy the equity portion of the consideration paid in the March 2013 Acquisition, the Southern Dome Acquisition and the MCE Acquisition. In 2014, we issued 1,964,957 of common units to satisfy the equity portion of the consideration paid in the CEU Acquisition, the MCCS Acquisition, and the Services Acquisition, respectively. See "Note 2 - Acquisitions" for additional discussion of these transactions.

Equity Offering. On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. We received net proceeds of approximately $76.2 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.3 million. We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds used to fund the cash portion of the Services Acquisition and related acquisition costs and for general corporate purposes.

At the Market Offering. On October 3, 2014, the Partnership and our general partner entered into an Equity Distribution Agreement (the “EDA”) with BMO Capital Markets Corp. (the “Sales Agent”). Pursuant to the terms of the EDA, the Partnership may sell, from time to time through or to the Sales Agent, common units representing limited partner interests in the Partnership having an aggregate offering price of up to $50.0 million. Sales of such common units, if any, will be made by means of ordinary brokers’ transactions through the facilities of the New York Stock Exchange ("NYSE") at market prices, or as otherwise agreed by the Partnership and the Sales Agent. On October 6, 2014, the Partnership sold 720,000 common units under the EDA for proceeds of approximately $16.2 million, net of offering costs, which included a commission to the Sales Agent of 1.75% on the principal amount of the offering. Proceeds were used to pay down a portion of the Partnership's outstanding debt and for general corporate purposes. No additional sales were made through December 31, 2014.

Distributions

The common units and the subordinated units are separate classes of limited partner interests. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement.

Subordinated Units. As discussed above, all of the subordinated units are held by NSEC. The partnership agreement provides that, during the subordination period, common units have the right to receive distributions of Available Cash from Operating Surplus (each as defined in the partnership agreement) quarterly in an amount equal to $0.525 per unit (the “Minimum Quarterly Distribution”), plus any arrearages of the Minimum Quarterly Distribution on common units from prior quarters, before any distributions of Available Cash from Operating Surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units are not entitled to receive distributions until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. Additionally, beginning with the first quarter of 2013, if our average production declines below 3,200 Boe/d for any preceding four-quarter period, then the subordinated units will not be entitled to receive the quarterly distributions otherwise payable on the subordinated units for such quarter.

The subordination period will end on the first business day after the Partnership has earned and paid at least (i) $2.10 (the Minimum Quarterly Distribution on an annualized basis) on each outstanding common unit, subordinated unit and general partner unit for each of twelve consecutive quarters ending on or after December 31, 2015 or (ii) $2.63 (125% of the annualized Minimum Quarterly Distribution) on each outstanding common unit, subordinated unit and general partner unit and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date. When the subordination period

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ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages. During the subordination period, distributions pertaining to any quarter in which the subordinated units are not entitled to receive distributions due solely to the minimum annual production requirement shall be included for purposes of determining if requirements have otherwise been met for twelve consecutive quarters with respect to aggregate distributions equaling or exceeding the minimum quarterly distribution on all common, subordinated, general partner units and any other partnership interests that are senior or equal in right of distribution to the subordinated units were earned in respect of such quarter.

Based on the distributable cash flow attributable to the fourth quarter of 2014, the distribution per common unit declared and paid in February 2015 was $0.20. As this is below the Minimum Quarterly Distribution per the partnership agreement, the subordinated units did not receive distributions for this period. Additionally, the subordinated units are not entitled to receive distributions until the common units receive an amount equal to the Minimum Quarterly Distribution and all cumulative arrearages, or approximately $5.3 million.

Incentive Distribution Rights. Our general partner currently holds incentive distribution rights (“IDRs”), which may be transferred separately from the general partner interest, subject to restrictions as discussed in the partnership agreement. The following table illustrates the allocations of available cash from operating surplus between unitholders and the general partner based on the specified target distribution levels.



	Total Quarterly			Marginal Percentage Interest in Distributions (1)
	Distributions per Unit			Unitholders	General Partner (2)
Minimum Quarterly Distribution	$0.525			99%	1%
First Target Distribution	$0.525	-	$0.60375	99%	1%
Second Target Distribution	$0.60376	-	$0.65625	86%	14%
Thereafter	above		$0.65625	76%	24%

_______________

(1) Represents the percentage interest in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

(2) Includes the 1% general partner interest as of December 31, 2014 and assumes contribution of any additional capital necessary to maintain the current general partner interest, retention of IDRs by the general partner and no arrearages on common units.



Distributions	Payable Date	Distribution per Unit		Common Units		Subordinated Units		General Partner Units		Total
2014
First Quarter	May 15, 2014	$	0.580	$	7,852	$	1,279	$	90	$	9,221
Second Quarter	August 15, 2014	$	0.585	$	9,025	$	1,290	$	91	$	10,406
Third Quarter	November 14, 2014	$	0.585	$	9,454	$	1,290	$	91	$	10,835
Fourth Quarter (3)	February 13, 2015	$	0.200	$	3,281	$	—	$	31	$	3,312

2013
First Quarter (1)	May 15, 2013	$	0.274	$	1,857	$	605	$	43	$	2,505
Second Quarter	August 15, 2013	$	0.550	$	3,725	$	1,213	$	85	$	5,023
Third Quarter	November 15, 2013	$	0.575	$	3,895	$	1,268	$	89	$	5,252
Fourth Quarter (2)	February 14, 2014	$	0.575	$	4,681	$	1,268	$	89	$	6,038

_______________


(1)	Prorated to reflect 47 days of the quarterly cash distribution of $0.525 per unit.

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(2)	Distributions were not paid on the 1,947,033 common units issued in conjunction with the MCE Acquisition pursuant to an arrangement with the sellers to forgo their rights to distributions for the fourth quarter of 2013 on these units.

(3)

As discussed above under "Incentive Distribution Rights" and pursuant to our partnership agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. No such incentive distributions were made to our general partner as quarterly distributions declared by the board of directors for 2014 and 2013 did not exceed the specified targets.

See "Note 17 - Subsequent Events" for discussion of distribution declared in January 2015.

Noncontrolling Interest

As part of the MCE Acquisition, certain former owners of MCE retained Class B Units in MCE. The MCE partnership agreement provides that the Class B Units have the right to receive an increasing percentage (15%, 25% and 50%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved based on results of MCE. Generally, the specified target distribution levels for the allocations of MCE's available cash from operating surplus between the Partnership and the Class B unitholders are adjusted for any capital contribution made by the Partnership to MCE as provided for in the MCE partnership agreement. (However, in the case of the contribution of the businesses acquired in the Services Acquisition the target distributions levels were not adjusted. Instead, the MCE partnership agreement was amended to provide that the Class B units will not participate in distributions of available cash provided by the operations of EFS and RPS.) Specifically, the target distributions are proportionally adjusted by 3.75% of an additional contribution of cash, cash equivalents or the value of contributed property, as further discussed in the partnership agreement. At any time after the Partnership has made four consecutive distributions to the Class B unitholders, the Class B unitholders have the right to reset, at higher levels, the minimum target distributions. As these Class B Units are not held by the Partnership, they are presented as noncontrolling interest in the accompanying consolidated financial statements. Any distribution to the Class B Units will be recognized in the period earned and recorded as a reduction to net income attributable to the Partnership.

The following table illustrates the allocations of MCE's available cash from operating surplus between the Partnership and the Class B unitholders based on the specified target distribution levels. As a result of the MCCS Acquisition, the specified target distribution levels for the allocations of MCE's available cash from operating surplus between the Partnership and the Class B unitholders were adjusted for the contribution of MCCS to MCE by the Partnership as provided for in the MCE partnership agreement. The following table illustrates the allocations of MCE's available cash from operating surplus between the Class A unitholders and the Class B unitholders based on the specified target distribution levels as of December 31, 2014, as adjusted based on the MCCS Acquisition.



				Marginal Percentage Interest in Distributions
	Total Quarterly Distributions per MCE Unit			MCE Class A Unitholders (the Partnership)	MCE Class B Unitholders
Minimum Quarterly Distribution	$16,116			100%	—%
First Target Distribution	$18,533	to	$20,144	85%	15%
Second Target Distribution	$20,145	to	$24,173	75%	25%
Third Target Distribution and Thereafter	$24,174	and above		50%	50%

Based on MCE's distribution amounts, the MCE Class B unitholders were entitled to distributions of approximately $0.2 million for the third quarter of 2014. No distributions were due to the MCE Class B unitholders for the first, second or fourth quarters of 2014.

Equity Compensation

On August 18, 2011, NSEC 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

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shares vesting on the completion of the initial public offering of NSEC's common stock pursuant to a filed prospectus provided that the employees remain employed by NSEC on the applicable vesting dates subject to limited exceptions.

We may grant awards of the Partnership's common units to employees under the Partnership's Long-Term Incentive Plan ("LTIP") or Fair Market Value Purchase Plan ("FMVPP"). Such awards are valued based upon the market value of common units on the date of grant and expensed over the relevant vesting period to the extent the awards contain a service requirement. If there is no service requirement, the awards are expensed at the time of grant.

On February 13, 2013, the Partnership granted 367,500 units of restricted common units to consultants, officers and other employees. Disposition of the units is restricted until the termination of the subordination period. The restricted units do not contain a future service requirement from the recipients. Accordingly, the Partnership recorded compensation expense of $7.4 million related to these awards as general and administrative expense in the accompanying consolidated statements of operations for the year ended December 31, 2013.

On November 12, 2013, as part of the MCE Acquisition, the Partnership granted 99,768 restricted common units to employees of MCE. A portion of these, or 19,490 common units, had a one-year vesting period and were subject to vesting restrictions based on employment status. Equity-based compensation expense was recognized straight-line over the one-year vesting period for the fair value of these units and included in general and administrative expense in the accompanying consolidated statements of operations.

For the year ended December 31, 2014 and 2013, the Partnership recorded equity-based compensation expense for restricted common units of $0.7 million and $7.5 million, respectively. Additionally, $8.2 million and $0.4 million, an allocated amount of NSEC stock-based compensation related to these awards, for the year ended December 31, 2012 and the period January 1, 2013 to February 13, 2013, was recognized as general and administrative expense in the accompanying consolidated statements of operations for the years ended December 31, 2012 and 2013, respectively.

Unamortized equity-based compensation expense related to these awards was $0.2 million as of December 31, 2014 and will be recognized on a straight line basis over 1.2 years.

Restricted equity, excluding phantom units, activity for the year ended December 31, 2014 and period from February 13, 2013 through December 31, 2013 was as follows:



	Number of Shares		Weighted-Average Grant Date Fair Value
Granted	467,268		$	20.56
Vested	—		$	—
Unvested restricted units outstanding at December 31, 2013	467,268		$	20.56
Granted	27,275		$	22.63
Vested	(45,985	)	$	(21.77	)
Forfeited/Canceled	(2,600	)	$	22.64
Unvested restricted units outstanding at December 31, 2014	445,958		$	20.51

Phantom Units. In conjunction with the Services Acquisition, the Partnership granted 432,038 phantom units, which represent the right to receive common units or cash equal to the value of the associated common units, to employees of EFS and RPS under the FMVPP. The phantom units vest over a period not to exceed 2 years. If a phantom unit is forfeited, the associated common units are released from escrow to an entity owned by the former owners of EFS and RPS. Except as otherwise provided in the Phantom Unit Agreement, phantom units subject to forfeiture restrictions may be forfeited upon termination of employment prior to the end of the vesting period. Although ownership of common units related to the vesting of such phantom units does not transfer to the holder until the phantom units vest, the recipients have distribution equivalent rights on these phantom units from the date of grant.

Although the phantom unit grants may be settled in either common units or cash at the holder's election, the settlement of the phantom units upon vesting will be made from a transfer or sale of the associated common units that were issued to an escrow account in conjunction with the Services Acquisition. As a result, the 401,171 phantom units with a service requirement valued at $10.1 million, were measured at fair market value of the Partnership’s common units on the grant date and are being expensed over the vesting period in accordance with accounting guidance for equity compensation. For the year ended December 31, 2014, the Partnership recorded equity-based compensation expense for phantom units of approximately $2.5 million. At December 31,

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2014, approximately $7.6 million remains to be expensed on a straight line basis over 1.5 years. The associated common units held in escrow are reflected as contra equity on the accompanying consolidated balance sheet at December 31, 2014.

10. Earnings per Unit

The Partnership’s net income is allocated to the common, subordinated and general partner unitholders, in accordance with their respective ownership percentages, and when applicable, giving effect to unvested units granted under the Partnership’s LTIP and incentive distributions allocable to the general partner. The allocation of undistributed earnings, or net income in excess of distributions, to the incentive distribution rights is limited to available cash (as defined by the partnership agreement) for the period. We present earnings per unit regardless of whether such earnings would or could be distributed under the terms of our partnership agreement. Accordingly, the reported earnings per unit is not indicative of potential cash distributions that may be made based on historical or future earnings. Basic and diluted net income per unit is calculated by dividing net income attributable to each class of unit by the weighted average number of units outstanding during the period. Any common units issued during the period are included on a weighted average basis for the days in which they were outstanding. During the year ended December 31, 2014, LTIP awards of 5,349 common units were excluded in the computation of diluted loss per unit. The Partnership had no potential common units outstanding as of December 31, 2013. Therefore, basic and diluted earnings per unit are the same for the year ended December 31, 2013.

Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. The Partnership’s earnings per unit calculations, which allocate earnings to the general partner based on the general partner interest, reflect that, while such distribution to the general partner with respect to its general partner interest was made, no incentive distributions were permitted or made to the general partner because quarterly distributions declared by the board of directors for 2013 and 2014 periods did not exceed the specified targets.

Basic and diluted earnings per unit for the year ended December 31, 2014 and the period February 13, 2013 through December 31, 2013 were computed as follows (in thousands, except per unit amounts):



	Year Ended December 31, 2014									February 13, 2013 through December 31, 2013
	Common Units			Subordinated Units			General Partner			Common Units		Subordinated Units		General Partner
Net (loss) income	$	(35,652	)	$	(6,256	)	$	(409	)	$	16,929	$	4,099	$	291
Weighted average units outstanding	13,517			2,205			155			6,995		2,205		155
Basic and diluted (loss) income per unit	$	(2.64	)	$	(2.84	)	$	(2.64	)	$	2.42	$	1.86	$	1.88

11. Related Party Transactions

Ownership. The Partnership is controlled by the Partnership's general partner, which is owned 69.4% by Kristian Kos, the Chairman and Chief Executive Officer of our general partner, and 25.0% by David J. Chernicky, the former Chairman of the board of directors of our general partner. Mr. Kos beneficially owns approximately 5.3% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through Deylau, LLC, an entity he controls. As of December 31, 2014, Mr. Chernicky beneficially owned approximately 15.6% of the Partnership's outstanding common units, including common units awarded under the Partnership's LTIP, and units owned through NSEC and Scintilla, entities that he controls. In addition, Mr. Chernicky beneficially owns 5.6% of our general partner and 100% of the 2,205,000 subordinated units through his control of NSEC. As a result of Mr. Chernicky's ownership of the Partnership and his ownership of all of the membership interests in New Dominion, which operates all of the Partnership's oil and natural gas properties, transactions with New Dominion are deemed to be with a related party.

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

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New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated was approximately $0.4 million as of both December 31, 2014 and December 31, 2013, all of which is classified as a long-term liability in the accompanying consolidated balance sheets. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.

Under agreements with New Dominion, the Partnership incurred charges and fees as follows for the years ended December 31, 2014, 2013 and 2012 (in thousands):



	Year Ended December 31,
	2014		2013		2012
Producing overhead and supervision charges	$	2,905	$	1,636	$	599
Drilling and completion supervision charges	368		520		27
Saltwater disposal fees	1,235		696		1,642
Total expenses incurred	$	4,508	$	2,852	$	2,268

At December 31, 2014 and December 31, 2013, $1.9 million and $1.3 million, respectively, were due to New Dominion for charges and fees under operating agreements and included in accounts payable - related party in the accompanying consolidated balance sheets. See "Note 15 - Commitments and Contingencies" for discussion of litigation with New Dominion.

NSEC. Under an agreement by and among NSEC, the Partnership and our general partner, NSEC provided administrative services for the Partnership from February 13, 2013 through December 31, 2013. For the year ended December 31, 2013, fees paid for such services were $2.4 million and were included in general and administrative expenses in the accompanying consolidated statements of operations.

New Source Energy GP, LLC. Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the year ended December 31, 2014, the amount paid to our general partner for such reimbursements was $3.9 million and was included in general and administrative expenses in the accompanying consolidated statements of operations. Additionally, we received and re paid approximately $1.5 million to our general partner during the year ended December 31, 2014 for operational cash advances. At December 31, 2014, $2.3 million was due to our general partner for reimbursement and included in accounts payable - related party in the accompanying consolidated balance sheet.

Acquisitions. As described in "Note 2 - Acquisitions," we acquired oil and natural gas properties, MCE and MCCS from related parties. As these acquisitions were with related parties, the transactions were subject to approval by the board of directors of the Partnership's general partner, based on the approval and recommendation of its conflicts committee.

As discussed in "Note 2 - Acquisitions," Mr. Kos was a 36% owner of MCE prior to the MCE Acquisition. Additionally, Dikran Tourian, the President and Chief Operating Officer of our general partner and member of our general partner's board of directors, was a 36% owner of MCE prior to the MCE Acquisition. In conjunction with the MCE Acquisition, Mr. Kos and Mr. Tourian retained Class B units that are entitled to incentive distributions as discussed in "Note 9 - Equity" as well as contingent consideration as discussed in "Note 3 - Contingent Consideration." In the third quarter of 2014, the Class B unit distribution targets were met.

On June 26, 2014, we exercised our option to acquire MCCS, which was owned by Mr. Kos and Mr. Tourian. See "Note 2 - Acquisitions" for discussion of this acquisition and "Note 3 Contingent Consideration" for discussion of the MCCS Contingent Consideration. As part of the acquisition of MCCS, we assumed a payable to an entity owned by Mr. Kos and Mr. Tourian. As of December 31, 2014, the payable of $0.7 million had been paid.

See "Note 17 - Subsequent Events" for discussion of land acquired we acquired from Mr. Kos and Mr. Tourian in 2015.

Transactions with Chief Financial Officer. The Partnership engaged Finley & Cook, PLLC ("Finley & Cook") to provide various accounting services on our behalf during the years ended December 31, 2014 and 2013. Richard Finley, the Chief Financial Officer of our general partner, was an equity member of Finley & Cook, holding a 31.5% ownership interest until October 2014. The Partnership paid Finley & Cook approximately $0.4 million in fees for the year ended December 31, 2014. NSEC engaged Finley & Cook to provide various accounting services on our behalf during the year ended December 31, 2013. Fees for such accounting services were included in the amounts paid to NSEC, as discussed above.

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12. Property, Plant and Equipment

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

The Partnership does not have any costs associated with its oil and natural gas properties that are excluded from amortization. The average rates used for depletion of oil and natural gas properties were $14.92 per Boe in 2014, $12.42 per Boe in 2013 and $12.51 per Boe in 2012.

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



	December 31, 2014			December 31, 2013
Vehicles and transportation equipment	$	15,891		$	561
Machinery and equipment	44,441			4,757
Office furniture and equipment	1,069			79
Iron	12,258			2,971
Total	73,659			8,368
Less: accumulated depreciation	(4,773		)	(202		)
Property and equipment, net	$	68,886		$	8,166

13. Asset Retirement Obligations

A reconciliation of the aggregate carrying amounts of the asset retirement obligations for the years ended December 31, 2014, 2013 and 2012 is as follows (in thousands):



	2014			2013		2012
Asset retirement obligations at January 1	$	3,455		$	1,510	$	1,411
Liability incurred upon acquiring and drilling wells	249			1,585		34
Revisions	(238		)	151		(51		)
Liability settled or disposed	(112		)	—		—
Accretion	327			209		116
Asset retirement obligations at December 31	3,681			3,455		1,510
Less: current portion	113			—		—
Asset retirement obligations, net of current	$	3,568		$	3,455	$	1,510

14. Accounts Payable and Accrued Liabilities

Accounts payable and accrued expenses consist of the following (in thousands):

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	December 31,
	2014		2013
Accounts payable trade	$	9,028	$	1,922
Accounts payable - other	3,754		318
Accrued wages and benefits	1,689		338
Accrued franchise and sales taxes	301		385
Accrued interest	188		304
Other	366		—
Total accounts payable and accrued expenses	$	15,326	$	3,267

15. Commitments and Contingencies

Commitments

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

On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into a development agreement (the "Development Agreement") with NSEC and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, the Partnership has agreed to maintain an average annual maintenance drilling budget of at least $8.2 million to drill certain of the Partnership’s proved undeveloped locations and maintain the Partnership’s producing wells. As of December 31, 2014, we had incurred $23.1 million towards the annual maintenance drilling budget. Based on amounts incurred in 2013 and 2014, we have fulfilled our commitment for the maintenance drilling budget under the Development Agreement.

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

See "Note 3 - Contingent Consideration" for discussion of contingencies related to certain acquisitions.

Operating Lease Obligations

We have obligations under noncancelable operating leases, primarily for office space and field locations. Total rental expense under operating leases for the years ended December 31, 2014 and 2013 was approximately $0.8 million and $0.1 million, respectively. The following is schedule by year of lease obligations and minimum lease payments for non-cancelable leases with a term of more than one year at December 31, 2014 (in thousands):

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Year
2015	$	1,299
2016	1,126
2017	650
2018	424
2019	312
Thereafter	520
Total	$	4,331

Legal Matters

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

On February 23, 2015, the defendants filed several motions to dismiss the claims raised in the plaintiffs’ petition, including motions by the Partnership and our general partner that (i) the defendants' claims fail to state a claim; (ii) the defendants' claims are time barred by statues of limitations; and (iii) Tulsa County is an improper venue. Subsequent to the filing by the defendants of their motions to dismiss, the parties agreed to a mediation to be held on March 24, 2015. The Partnership and the other defendants intend to defend this lawsuit vigorously and believe the plaintiffs' claims are without merit. This lawsuit is in the early stages and, accordingly, an estimate of reasonably possible losses associated with this action, if any, cannot be made until the facts, circumstances and legal theories relating to the plaintiffs' claims and the defendants’ defenses are fully disclosed and analyzed. The Partnership has not established any reserves relating to this action.

In addition to the proceeding described above, on January 29, 2015, the Partnership received notice from New Dominion that it had purchased from NSEC certain obligations claimed to be owed by the Partnership to NSEC. The total amount of the purported claims totaled approximately $1.9 million. In February and March 2015, New Dominion withheld revenue from the Partnership's sold oil and natural gas production in satisfaction of the claims. As with the proceeding described above, the Partnership intends to pursue this matter vigorously and believes the claims are without any substantial merit. This claim will be addressed at the March 24, 2015 mediation described above. The Partnership has not established any reserves relating to this action.

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

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

Any liability on the part of New Dominion, as contract operator, would be allocated to the working interest owners to pay their proportionate share of such liability. While the outcome and impact on the Partnership of this proceeding cannot be predicted

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with certainty, management believes a loss of up to $250,000 may be reasonably possible. Due to the uncertainty, no reserve has been established for this matter.

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

16. Business Segment Information

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

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

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	Exploration and Production			Oilfield Services (1)			Total
Year Ended December 31, 2014
Revenues	$	61,488		$	104,155		$	165,643
Direct operating expenses	21,450			60,904			82,354
Segment margin	40,038			43,251			83,289
General and administrative expenses	11,051			17,620			28,671
Change in fair value of contingent consideration	(9,031		)	—			(9,031		)
Impairment	—			59,000			59,000
Depreciation, depletion, amortization and accretion	25,113			29,566			54,679
Income (loss) from operations	$	12,905		$	(62,935	)	$	(50,030	)

Interest expense	$	(3,726	)	$	(1,315	)	$	(5,041	)
Gain on derivative contracts, net	$	10,707		$	—		$	10,707
Gain on investment in acquired business	$	2,298		$	—		$	2,298

Capital expenditures (2)	$	23,662		$	21,349		$	45,011
At December 31, 2014
Total assets	$	201,097		$	176,368		$	377,465

Year Ended December 31, 2013
Revenues	$	46,937		$	3,738		$	50,675
Direct operating expenses	15,300			2,040			17,340
Segment margin	31,637			1,698			33,335
General and administrative expenses (3)	13,787			973			14,760
Change in fair value of contingent consideration	(1,600		)	—			(1,600		)
Depreciation, depletion, amortization and accretion	16,799			1,966			18,765
Income (loss) from operations	$	2,651		$	(1,241	)	$	1,410

Interest expense	$	(3,951	)	$	(127	)	$	(4,078	)
Gain on derivative contracts, net	$	(5,548	)	$	—		$	(5,548	)
Gain on investment in acquired business	$	22,709		$	—		$	22,709

Capital expenditures (2)	$	48,319		$	445		$	48,764
At December 31, 2013
Total assets	$	181,440		$	73,270		$	254,710

_______________


(1)	The Partnership's oilfield services segment was established with the MCE Acquisition that occurred in November 2013. See "Note 2 - Acquisitions" for discussion.


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


(3)	Includes $7.7 million of compensation expense related to common units granted to consultants, officers, directors and employees in conjunction with our initial public offering.

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Major Customers. Historically, the majority of the Partnership's revenue has been from oil and natural gas properties in the Hunton formation in east-central Oklahoma. The addition of our oilfield services segment in November 2013 and the acquisition of three oilfield service companies in June 2014 expanded our customer base. The following table reflects purchases by customers exceeding 10% of our total sales for the years ended December 31:



Purchaser	2014	2013	2012
Scissortail	26%	80%	84%
United Petroleum Purchasing	< 10%	14%	16%

No one customer from our oilfield services business comprised more than 10% of our total sales for the years ended December 31, 2014 or 2013. The Partnership believes the loss of any one purchaser or customer would not have a material adverse effect on the ability of the Partnership to sell its production or services to a replacement purchaser.

17. Subsequent Events

Distributions. On January 20, 2015, the Partnership declared quarterly distributions of $0.20 per unit to unitholders of record, including holders of common and general partner units for the fourth quarter of 2014. The following distributions were paid on February 13, 2015 to holders of record as of the close of business on February 2, 2015 (in thousands):



	Common Units		Subordinated Units		General Partner Units		Total
Distributions	$	3,281	$	—	$	31	$	3,312

Property Acquisition. On January 9, 2015, MCLP acquired two separate parcels of land, one located in Canadian County, Oklahoma and one located in Ector County, Texas, from an entity owned 50% by Mr. Kos, Chief Executive Officer of our general partner, and 50% by Mr. Tourian, President and Chief Operating Officer of our general partner, for approximately $0.9 million. Additionally, on February 24, 2015, MCLP acquired land located in Karnes County, Texas from an entity owned 50% by Mr. Kos and 50% by Mr. Tourian for approximately $0.5 million. The purchase price for each transaction was determined based on independent third-party appraisals for each property. In each transaction, a promissory note for the entire purchase price was issued by MCLP to Mr. Kos and Mr. Tourian.

18. Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

The supplemental information includes capitalized costs related to oil, natural gas, and NGL producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil, natural gas, and NGL producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows ("Standardized Measure") associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the Standardized Measure associated with proved oil, natural gas and NGL reserves.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Partnership’s capitalized costs for oil, natural gas, and NGL activities consisted of the following (in thousands)

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	December 31,
	2014			2013			2012
Proved	$	332,413		291,829			$	202,795
Less: accumulated depreciation, depletion and amortization	(153,734		)	(128,961		)	(112,372		)
Net capitalized costs for oil and natural gas properties	$	178,679		$	162,868		$	90,423

Costs Incurred in Oil and Natural Gas Property Acquisition and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follow (in thousands):



	Year Ended December 31,
	2014		2013		2012
Property acquisition costs	$	18,520	$	58,014	$	—
Development costs	22,793		29,451		11,382
Total costs incurred	$	41,313	$	87,465	$	11,382

There were no exploration costs incurred in 2014, 2013 or 2012. Additionally, no internal costs or interest expense were capitalized in 2014, 2013 and 2012.

Results of Operations for Oil, Natural Gas, and NGL Producing Activities

The Partnership’s results of operations from oil, natural gas, and NGL producing activities for each of the years 2014, 2013 and 2012 are shown in the following table (in thousands):



	Year Ended December 31,
	2014		2013		2012
Revenues	$	61,488	$	46,937	$	35,596
Expenses
Production	21,450		15,300		7,361
Depreciation and depletion	24,786		16,590		14,409
Accretion of asset retirement obligations	327		209		116
Total expenses	46,563		32,099		21,886
Results of operations for oil and natural gas producing activities	$	14,925	$	14,838	$	13,710

Oil, Natural Gas and NGL Reserve Quantities

Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Partnership’s senior engineer and independent petroleum consultant relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Partnership’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:


•	the quality and quantity of available data and the engineering and geological interpretation of that data;


•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;


•	the accuracy of mandated economic assumptions such as the future prices of oil, natural gas and NGLs; and


•	the judgment of personnel preparing the estimates.

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Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

Oil, natural gas, and natural gas liquid 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.

The Partnership's 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, 2014, 2013 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 Securities and Exchange Commission and the FASB.

The pricing used for estimates of reserves as of December 31, 2014, 2013 and 2012, was based on an unweighted twelve-month average WTI posted price of $94.99, $96.78, and $94.71, respectively, per Bbl for oil and a Henry Hub spot natural gas price of $4.35, $3.67, and $2.76, respectively, per Mcf for natural gas. NGLs were priced at 38%, 38%, and 36% of the oil prices for the periods ended December 31, 2014, 2013 and 2012, respectively, which approximates the realizable value received.

The following table summarizes the prices utilized in the reserve estimates as adjusted for location, grade and quality as of December 31:



	Year Ended December 31,
	2014		2013		2012
Oil	$	91.98	$	93.71	$	92.74
Natural gas	$	4.13	$	3.55	$	2.59
NGL	$	34.95	$	35.61	$	33.39

The following table provides a rollforward of the total net proved reserves for the years ended December 31, 2012, 2013 and 2014, as well as proved developed and proved undeveloped reserves at the end of each respective year. Oil and NGL volumes are expressed in Bbls and natural gas volumes are expressed in Mcf.

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	Oil (Bbls)		Natural Gas (Mcf)		NGL (Bbls)		Total (Boe)
Total proved reserves
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	)
Purchases of reserves	—		—		—		—
Extensions and discoveries (1)	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

Balance, January 1, 2013	529,190		24,135,100		9,703,920		14,255,627
Revisions	(49,507	)	1,897,316		(857,896	)	(591,184	)
Purchases of reserves	1,031,040		11,889,850		4,727,060		7,739,742
Extensions and discoveries (1)	13,130		1,092,500		374,390		569,603
Production	(84,273	)	(2,764,336	)	(790,234	)	(1,335,230	)
Balance, December 31, 2013	1,439,580		36,250,430		13,157,240		20,638,558

Proved developed reserves	922,190		19,625,190		8,290,570		12,483,625
Proved undeveloped reserves	517,390		16,625,240		4,866,670		8,154,933
Total proved reserves	1,439,580		36,250,430		13,157,240		20,638,558

Balance, January 1, 2014	1,439,580		36,250,430		13,157,240		20,638,558
Revisions (2)	(404,382	)	(7,304,864	)	(3,889,584	)	(5,511,443	)
Purchases of reserves	717,480		5,370,830		247,540		1,860,158
Extensions and discoveries (3)	60,840		1,849,500		621,580		990,670
Production	(163,338	)	(3,673,836	)	(885,117	)	(1,660,761	)
Balance, December 31, 2014	1,650,180		32,492,060		9,251,659		16,317,182

Proved developed reserves	1,516,850		25,898,620		7,706,900		13,540,186
Proved undeveloped reserves	133,330		6,593,440		1,544,759		2,776,996
Total proved reserves	1,650,180		32,492,060		9,251,659		16,317,182

_______________


(1)	Extensions and discoveries are due to development drilling in the Golden Lane area.


(2)	Revisions are primarily attributable to the reclassification of certain proved undeveloped reserves to probable reserves because our expected drilling plan has been curtailed as a result of low commodity prices and rising costs to drill wells.


(3)	Extensions and discoveries are due to wells drilled in the Golden Lane field in 2014.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure is computed by applying the twelve-month unweighted average of the first-day-of-the-month pricing for oil, natural gas and NGL to the estimated future production of proved oil, natural gas and NGL 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.

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Discounted future cash flow estimates like those shown herein are not intended to represent estimates of the fair value of the Partnership’s oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil, natural gas and NGL 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 as of the periods presented below (in thousands):



	2014			2013			2012
Future production revenues	$	609,362		$	732,340		$	435,670
Future costs:
Production	(220,350		)	(223,582		)	(121,541		)
Development	(48,216		)	(110,881		)	(52,032		)
Income tax expense(1)	—			—			(85,090		)
10% annual discount for estimated timing of cash flows	(161,536		)	(185,152		)	(82,746		)
Standardized measure of discounted net cash flows	$	179,260		$	212,725		$	94,261

_______________


(1)	Our Standardized Measure as of December 31, 2012 includes effects of income taxes. The Partnership was not a taxable entity in 2013 or 2014.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table provides a rollforward of the Standardized Measure for the years ended December 31, (in thousands):



	2014			2013			2012
Discounted future net cash flows at beginning of year	$	212,725		$	94,261		$	153,333
Increase (decrease)
Sales and transfers, net of production costs	(40,321		)	(31,637		)	(28,235		)
Net changes in prices and production costs	2,109			3,952			(93,618		)
Extensions and discoveries	18,482			25,280			8,688
Changes in future development costs	9,886			(61,939		)	8,350
Previous development costs incurred	23,076			29,451			11,382
Acquisition of reserves in place	29,955			76,596			—
Revisions of previous quantity estimates	(72,636		)	(7,035		)	(5,833		)
Changes in income taxes	—			47,387			33,532
Timing and other	(25,289		)	26,983			(8,671		)
Accretion of discount	21,273			9,426			15,333
Net increase (decrease)	(33,465		)	118,464			(59,072		)
Discounted future net cash flows at end of year	$	179,260		$	212,725		$	94,261

19. Quarterly Results of Operations (unaudited)

The following transactions are reflected in the quarterly results below:


•	oil and natural gas properties located in the Golden Lane and Luther fields in Oklahoma in March 2013;


•	oil and natural gas properties located in the Southern Dome field in Oklahoma in May 2013;


•	oil and natural gas properties located in the Golden Lane field in Oklahoma in July 2013;


•	working interests and related undeveloped leasehold rights located in the Southern Dome field in Oklahoma in October 2013 and January 2014;

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•	MCE Entities, oilfield services companies, in November 2013; and


•	MCCS, EFS and RPS, oilfield services companies, in June 2014.

The following table summarizes quarterly financial data for the years ended December 31, 2014 and 2013 (in thousands, except per unit data):



	Quarter Ended
2014	March 31			June 30		September 30			December 31

Revenues	$	27,427		$	26,818	$	56,424		$	54,974
Income (loss) from operations (1) (2) (3)	2,572			1,690		(5,075		)	(49,217		)
Income tax expense	—			—		—			—
Net (loss) income (1) (2) (3)	$	(1,531	)	$	1,586	$	(2,754	)	$	(39,376	)
(Loss) earnings per common unit
Basic	$	(0.12	)	$	0.11	$	(0.17	)	$	(2.11	)
Diluted	$	(0.12	)	$	0.11	$	(0.17	)	$	(2.11	)

2013
Revenues	$	9,360		$	10,649	$	12,431		$	18,235
(Loss) income from operations (4)	(6,118		)	2,456		2,121			2,951
Income tax benefit	12,126			—		—			—
Net (loss) income (4)	$	(1,397	)	$	8,151	$	(1,986	)	$	21,854
(Loss) earnings per common unit (5)
Basic	$	(0.87	)	$	0.89	$	(0.22	)	$	2.05
Diluted	$	(0.87	)	$	0.89	$	(0.22	)	$	2.05

_______________


(1)	Includes amortization of intangible assets of $3.1 million, $3.1 million, $9.4 million and $9.4 million for the first, second, third and fourth quarters, respectively.


(2)	Includes (loss) gain on commodity derivative contracts of $(3.1) million, $(1.4) million, $3.8 million and $11.5 million for the first, second, third and fourth quarters, respectively.


(3)	Includes impairment of $35.0 million on our oilfield services segment goodwill and $24.0 million on certain of our oilfield services segment intangible assets for the fourth quarter.


(4)	Includes (loss) gain on commodity derivative contracts of $(5.3) million, $6.2 million, $(3.5) million and $(3.0) million for the first, second, third and fourth quarters, respectively.


(5)	The first quarter 2013 loss per unit only applies to earnings from February 14, 2013 (the Partnership's initial public offering date) to December 31, 2013.

F-49

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

20. Parent Company Financial Information

As discussed in "Note 4 - Debt," certain of our subsidiaries have long-term debt outstanding which place restrictions on distributions of funds to the Partnership. As the Partnership's proportionate share of these subsidiaries' restricted net assets, which totaled approximately $74.0 million at December 31, 2014, represents a significant portion of our consolidated net assets, we are presenting the following parent financial information. The parent only financial information is prepared on the same basis of accounting as our consolidated financial statements, except that our subsidiaries are accounted for under the equity method of accounting.

F-50

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)

Balance Sheets



	December 31,
	2014			2013
	(in thousands, except unit amounts)
ASSETS
Current assets:
Cash	$	1,416		$	6,027
Accounts receivable, net	15,894			8,645
Derivative contracts	8,248			130
Other current assets	312			109
Total current assets	25,870			14,911

Oil and natural gas properties, at cost using full cost method of accounting:
Proved oil and natural gas properties	332,413			291,829
Less: Accumulated depreciation, depletion, and amortization	(153,734		)	(128,961		)
Total oil and natural gas properties, net	178,679			162,868
Property and equipment, net	365			—
Investment in subsidiary	118,185			66,867
Other assets	3,820			3,661
Total assets	$	326,919		$	248,307

LIABILITIES. PARENT NET INVESTMENT AND PARTNERS' CAPITAL:
Current liabilities:
Accounts payable and accrued liabilities	$	1,975		$	1,877
Accounts payable-related parties	4,237			7,348
Contingent consideration payable	11,572			—
Derivative contracts	—			3,167
Other current liabilities	113			—
Total current liabilities	17,897			12,392
Long-term debt	83,000			78,500
Contingent consideration payable	10,801			6,320
Asset retirement obligations	3,568			3,455
Other liabilities	339			387
Total liabilities	115,605			101,054
Commitments and contingencies
Unitholders' equity:
Common units (16,160,381 units issued and outstanding at December 31, 2014 and 9,599,578 units issued and outstanding at December 31, 2013)	231,510			151,773
Common units held in escrow	(6,955		)	—
Subordinated units (2,205,000 units issued and outstanding at December 31, 2014 and December 31, 2013)	(28,717		)	(17,334		)
General partner's units (155,102 units issued and outstanding at December 31, 2014 and December 31, 2013)	(1,944		)	(1,174		)
Total New Source Energy Partners L.P. unitholders' equity	193,894			133,265
Noncontrolling interest	17,420			13,988
Total unitholders' equity	211,314			147,253
Total liabilities and unitholders' equity	$	326,919		$	248,307

F-51

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)

Statements of Operations



	For the year ended December 31,
	2014			2013			2012
	(in thousands)
Revenues:
Oil sales	$	14,906		$	8,090		$	5,570
Natural gas sales	15,534			10,000			6,030
NGL sales	31,048			28,847			23,996
Total revenues	61,488			46,937			35,596
Operating costs and expenses:
Oil, natural gas and NGL production	18,617			12,631			6,217
Production taxes	2,833			2,669			1,144
Depreciation, depletion and amortization	24,786			16,590			14,409
Accretion	327			209			116
General and administrative	11,051			13,787			12,660
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
Total operating costs and expenses	48,583			44,286			34,546
Operating income	12,905			2,651			1,050
Other income (expense):
Interest expense	(3,726		)	(4,013		)	(3,202		)
Gain (loss) on derivative contracts, net	10,707			(5,548		)	7,057
Gain on investment in acquired business	2,298			22,709			—
Loss from subsidiary	(64,259		)	(1,303		)	—
(Loss) income before income taxes	(42,075		)	14,496			4,905
Income tax benefit (expense)	—			12,126			(1,796		)
Net (loss) income	(42,075		)	26,622			3,109
Less: net income attributable to noncontrolling interest	242			—			—
Net (loss) income attributable to New Source Energy Partners L.P.	$	(42,317	)	$	26,622		$	3,109

F-52

NEW SOURCE ENERGY PARTNERS L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED

NEW SOURCE ENERGY PARTNERS L.P. (PARENT ONLY)

Statements of Cash Flows



	Year ended December 31,
	2014			2013			2012
	(in thousands)
Cash Flows from Operating Activities:
Net (loss) income	$	(42,075	)	$	26,622		$	3,109
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Earnings from subsidiaries	64,259			1,303			—
Distributions of earnings from subsidiaries	4,406			—			—
Depreciation, depletion and amortization	24,786			16,590			14,409
Accretion	327			209			116
Amortization of deferred loan costs	603			479			603
Write off of loan costs due to debt refinancing	167			1,436			—
Equity-based compensation	644			7,839			8,204
Deferred income tax benefit	—			(12,024		)	1,694
Change in fair value of contingent consideration	(9,031		)	(1,600		)	—
Gain on investment in acquired business	(2,298		)	(22,709		)	—
(Gain) loss on derivative contracts, net	(10,707		)	5,548			(7,057		)
Cash (paid) received on settlement of derivative contracts	(1,773		)	(1,929		)	5,987
Payments for premiums on derivatives	—			(1,334		)	—
Changes in operating assets and liabilities:
Accounts receivable	1,096			(9,996		)	881
Other current assets and other assets	(203		)	256			—
Accounts payable and accrued liabilities	(994		)	7,617			(147		)
Net cash provided by operating activities	29,207			18,307			27,799
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired	(63,446		)	(22,102		)	—
Additions to oil and natural gas properties	(24,671		)	(28,476		)	(12,162		)
Additions to other property and equipment	(378		)	—			—
Contributions to subsidiaries	(5,000		)	(1,522		)	—
Net cash used in investing activities	(93,495		)	(52,100		)	(12,162		)
Cash Flows from Financing Activities:
Proceeds from borrowings	18,750			80,500			3,000
Payments on borrowings	(14,250		)	(70,000		)	(3,500		)
Payments for deferred loan costs	(356		)	(1,957		)	(64		)
Payment on subordinated note payable to parent	—			(25,000		)	—
Proceeds from sales of common units, net of offering costs	92,375			77,880			—
Proceeds from issuance of common units in private placement, net of offering costs	—			9,833			—
Payments of offering costs	(100		)	(361		)	(1,315		)
Distribution to NSEC	—			(18,295		)	(13,758		)
Distribution to unitholders	(36,742		)	(12,780		)	—
Net cash provided by (used in) financing activities	59,677			39,820			(15,637		)
Net change in cash and cash equivalents	(4,611		)	6,027			—
Cash and cash equivalents, beginning of period	6,027			—			—
Cash and cash equivalents, end of period	$	1,416		$	6,027		$	—

F-53

Table of Contents

EXHIBIT INDEX





		Incorporation by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith
2.1	Contribution Agreement, dated as of January 31, 2014, by and between New Source Energy Partners L.P. and CEU Paradigm, LLC	8-K	001-35809	2.1	2/5/2014
2.2	Contribution Agreement, dated as of June 26, 2014, among J. Mark Snodgrass, Brian N. Austin, Rod's Holdings, LLC Erick's Holdings, LLC, and New Source Energy Partners L.P.	8-K	001-35809	2.1	7/1/2014
3.1	Certificate of Limited Partnership of New Source Energy Partners L.P.	S-1	333-185754	3.1	1/11/2013
3.2	First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.	8-K	001-35809	3.1	2/15/2013
3.3	First Amendment to the First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.	8-K	001-35809	3.1	11/18/2013
3.4	Certificate of Formation of New Source Energy GP, LLC	S-1	333-185754	3.4	1/11/2013
3.5	First Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC	8-K	001-35809	3.2	2/15/2013
3.6	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC	8-K	001-35809	3.1	3/20/2013
4.1	Registration Rights Agreement, dated as of November 12, 2013, by and between New Source Energy Partners L.P. and Kristian B. Kos, Dikran Tourian, Danny R. Pickelsimer, Antranik Armoudian, Deylau, LLC and Signature Investments, LLC	8-K	001-35809	4.1	11/18/2013
10.1	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	8-K	001-35809	10.4	2/15/2013
10.2†	New Source Energy Partners L.P. Long-Term Incentive Plan, dated January 30, 2013	S-8	333-186673	4.3	2/13/2013
10.3†	Form of Restricted Unit Agreement (Subordination Period Vesting)	8-K	001-35809	10.1	2/12/2013
10.4†	Form of Restricted Unit Agreement (Time-based Vesting)	8-K	001-35809	10.2	2/12/2013
10.5†	New Source Energy Partners L.P. Fair Market Value Purchase Plan	8-K	001-35809	10.2	7/1/2014
10.6	Form of Director Indemnification Agreement	8-K	001-35809	10.5	2/15/2013
10.7	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	8-K	001-35809	10.2	2/15/2013

Table of Contents



10.8	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	8-K	001-35809	10.1	3/6/2013
10.9	Second Amendment to Credit Agreement, dated as of June 25, 2013, by and among the Partnership, as borrower, Bank of Montreal, as administrative agent, Associated Bank, N.A., as syndication agent, and the other lenders party thereto	8-K	001-35809	10.1	6/28/2013
10.10	Third Amendment to Credit Agreement, dated as of October 29, 2013, by and among the Partnership, as borrower, Bank of Montreal, as administrative agent, Associated Bank, N.A., as syndication agent, and the other lenders party thereto	8-K	001-35809	10.1	11/4/2013
10.11	Fourth Amendment to Credit Agreement, dated as of November 12, 2013, by and among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent, and the other lenders party thereto	8-K	001-35809	10.4	11/18/2013
10.12	Fifth Amendment to Credit Agreement, dated as of March 10, 2014, by and among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent, and the other lenders party thereto	10-Q	001-35089	10.1	5/15/2014
10.13	Sixth Amendment to Credit Agreement, dated as of August 15, 2014, by and among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent, and the other lenders party thereto					*
10.14	Option Agreement, dated as of November 12, 2013, by and between New Source Energy Partners L.P. and Kristian B. Kos, Dikran Tourian and Signature Investments, LLC	8-K	001-35809	10.1	11/18/2013
10.15	Amended and Restated Agreement of Limited Partnership of MCE, LP, dated as of November 12, 2013	8-K	001-35809	10.2	11/18/2013
10.16	Director Designation Agreement, dated as of November 12, 2013, by and between New Source Energy Partners L.P., New Source Energy GP, LLC, Deylau, LLC and Signature Investments, LLC	8-K	001-35809	10.3	11/18/2013
10.17	First Amended and Restated Loan and Security Agreement, dated June 26, 2014, by and between Erick Flowback Services, LLC, Rod's Production Services, L.L.C., Mark Snodgrass, Brian Austin, MCE, LP and Bank 7	8-K	001-35809	10.1	7/1/2014
12.1	Statement of Computation of Ratio of Earnings to Fixed Charges					*
21.1	List of Subsidiaries of New Source Energy Partners L.P.					*
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					*

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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.	*
101.INS(a)	XBRL Instance Document	*
101.SCH(a)	XBRL Schema Document	*
101.CAL(a)	XBRL Calculation Linkbase Document	*
101.DEF(a)	XBRL Definition Linkbase Document	*
101.LAB(a)	XBRL Labels Linkbase Document	*
101.PRE(a)	XBRL Presentation Linkbase Document	*

* Filed herewith.

** Furnished herewith.

† Management contract or compensatory plan or arrangement

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 March 20, 2015.



	New Source Energy Partners L.P.

	By:	New Source Energy GP, LLC, its general partner


	/s/ Kristian B. Kos
	By:	Kristian B. Kos
	Title:	Chairman and 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.

Table of Contents



Signature	Title	Date

/s/ Kristian B. Kos	Chairman of the Board	March 20, 2015
Kristian B. Kos	and Chief Executive Officer
	(Principal Executive Officer)

/s/ Richard D. Finley	Chief Financial Officer and Treasurer	March 20, 2015
Richard D. Finley	(Principal Financial Officer)

/s/ Dikran Tourian	President, Chief Operating Officer and	March 20, 2015
Dikran Tourian	Director

/s/ Amber N. Bonney	Vice President Accounting and	March 20, 2015
Amber N. Bonney	Principal Accounting Officer

/s/ Terry L. Toole	Director	March 20, 2015
Terry L. Toole

/s/ V. Bruce Thompson	Director	March 20, 2015
V. Bruce Thompson

/s/ John A. Raber	Director	March 20, 2015
John A. Raber

/s/ Charles Lee Reynolds III	Director	March 20, 2015
Charles Lee Reynolds III

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New Source Energy Partners (NSLP) Inactive 10-K2014 FY Annual report

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