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, 2013
| 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 No. 001-35809
| NEW SOURCE ENERGY PARTNERS L.P. | |
| (Exact name of registrant as specified in its charter) | |
| Delaware | 38-3888132 |
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) |
914 North Broadway, Suite 230 Oklahoma City, Oklahoma | 73102 |
| (Address of principal executive offices) | (Zip Code) |
| (Registrant's telephone number, including area code): (405) 272-3028 | |
Securities Registered Pursuant to Section 12(b) of the Act:
| Common Units Representing Limited Partner Interests | New York Stock Exchange |
| (Title of each class) | (Name of each exchange on which registered) |
Securities Registered Pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x 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 x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Annual Report on Form 10-K or any amendment to this Annual Report on Form 10-K. 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 o Non-accelerated filer þ (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 x
As of June 30, 2013, the last business day of the registrant's most recently completed second fiscal quarter, the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, was $86,700,000.
As of April 3, 2014, the registrant had 10,088,245 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: None.
TABLE OF CONTENTS
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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 SEC determines otherwise; |
| • | provide certain disclosure regarding executive compensation required of larger public companies; or |
| • | obtain shareholder approval of any golden parachute payments not previously approved. |
We will cease to be an “emerging growth company” upon the earliest of:
| • | when we have $1.0 billion or more in annual revenues; |
| • | when we have at least $700 million in market value of our common units held by non-affiliates; |
| • | when we issue more than $1.0 billion of non-convertible debt over a three-year period; or |
| • | the last day of the fiscal year following the fifth anniversary of our initial public offering. |
In addition, Section 107 of the JOBS Act also provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following includes a description of the meanings of some of the oil and natural gas industry terms used in this Annual Report on Form 10-K. All natural gas reserves and production reported in this Annual Report on Form 10-K are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit.
3-D seismic data: Geophysical data that depicts the subsurface strata in three dimensions.
Analogous Reservoir: Analogous reservoirs, as used in resource assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest); (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.
Basin: A large depression on the earth’s surface in which sediments accumulate.
Bbl: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bbl/d: One Bbl per day.
Boe: One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
Boe/d: One Boe per day.
Btu: One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree Fahrenheit.
Completion: The process of strengthening a well hole with casing, evaluating the pressure and temperature of the formation, and then installing the proper equipment to ensure an efficient flow of oil and natural gas out of the well.
Condensate: Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Conventional Reservoir: A reservoir in which buoyant forces keep hydrocarbons in place below a sealing caprock. Reservoir and fluid characteristics of conventional reservoirs typically permit oil or natural gas to flow readily into wellbores. The term is used to make a distinction from shale and other unconventional reservoirs, in which gas might be distributed throughout the reservoir at the basin scale, and in which buoyant forces or the influence of a water column on the location of hydrocarbons within the reservoir are not significant.
Conventional Resource Reservoir: A conventional reservoir demonstrating the characteristics defined by a resource play. Conventional resource plays are also referred to as transition zone reservoirs. The reservoir may be over or under-pressured. The conventional resource play is conducive to assembly-line operations, with upside potential to improve recoveries and efficiencies from enhanced methodologies including seismic, log interpretation, cores, drilling, completion and operations.
Development Costs: Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves;
(ii) drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;
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(iii) acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and
(iv) provide improved recovery systems.
Development Project: A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Developed Acreage: The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development Well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential: An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.
Dry Hole or Dry Well: A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Economically Producible: The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and natural gas producing activities.
Environmental Assessment: A study that can be required pursuant to federal law to assess the potential direct, indirect and cumulative impacts of a project.
Estimated Ultimate Recovery: Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
Exploitation: A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Exploratory Well: A well drilled to find and produce oil and natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Field: An area consisting of a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
Formation: A layer of rock which has distinct characteristics that differ from nearby rock.
Fracture Stimulation: A process whereby fluids mixed with proppants are injected into a wellbore under pressure to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.
Gross Acres or Gross Wells: The total acres or wells, as the case may be, in which we have working interest.
Horizontal Drilling: A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
MBoe: One thousand Boe.
MBoe/d: One thousand Boe per day.
Mcf: One thousand cubic feet of natural gas.
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Mcf/d: One Mcf per day.
MMBtu: One million Btu.
Net Acres or Net Wells: Gross acres or wells, as the case may be, multiplied by our working interest ownership percentage working interest.
Net Production: Production that is owned by us less royalties and production due others.
Net Revenue Interest: A working interest owner’s gross working interest in production less the royalty, overriding royalty, production payment and net profits interests.
NGLs: The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
NYMEX: New York Mercantile Exchange.
Oil: Oil and condensate and natural gas liquids.
Operator: The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Permeability: The measure of the ease with which fluid flows through a porous rock and is a function of interconnection between the pores.
Play: A geographic area with hydrocarbon potential.
Plugging and Abandonment: Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Porosity: The ratio of the void space in a rock to the bulk volume of that rock multiplied by 100 to express in percent.
Productive Well: A well that produces commercial quantities of hydrocarbons, exclusive of its capacity to produce at a reasonable rate of return.
Proved Developed Reserves: Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.
Proved Reserves: Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions
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include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves: Proved oil and natural gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Realized Price: The cash market price less all expected quality, transportation and demand adjustments.
Recompletion: The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reliable Technology: Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves: Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reserve Life: A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years. Reserve life is calculated by dividing proved reserve volumes at year-end by production volumes. In our calculation of reserve life, production volumes are based on annualized fourth quarter production and are adjusted, if necessary, to reflect property acquisitions and dispositions.
Reservoir: A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Resource Play: An accumulation of hydrocarbons known to exist over a large areal expanse that is believed to have a lower geological and/or commercial development risk. A resource play is a continuous hydrocarbon system over a contiguous geographical area that is regional in extent, exhibits both low exploration risk with consistent results, and predictable estimated ultimate recoveries. Performance is a function of reservoir geology, which includes variations in thickness, rock lithology, porosity, permeability, in-situ stress, minerology, and completion efficiency. Resource play reservoirs can be described using a statistical description and importantly, this statistical description changes little over time provided interference between wells is minimal. A resource play is conducive to assembly-line operations, with upside potential to improve recoveries and efficiencies from enhanced methodologies—seismic, log interpretation, cores, drilling, completion and operations.
Resources: Resources are quantities of oil and natural gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable and another portion may be considered unrecoverable. Resources include both discovered and undiscovered accumulations.
Spacing: The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.
Spot Price: The cash market price without reduction for expected quality, transportation and demand adjustments.
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Standardized Measure: The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue. Because we are a limited partnership, we are generally not subject to federal or state income taxes and thus make no provision for federal or state income taxes in the calculation of our standardized measure. Standardized measure does not give effect to derivative transactions.
Unconventional Reservoirs: A term used in the oil and natural gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds, or (3) gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes to produce economic flow rates.
Undeveloped Acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Wellbore: The hole drilled by the bit that is equipped for oil or natural gas production on a completed well. Also called well or borehole.
Working Interest: An interest in an oil and natural gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
Workover: Operations on a producing well to restore or increase production.
WTI: West Texas Intermediate.
The terms “analogous reservoir,” “development project,” “development well,” “economically producible,” “estimated ultimate recovery,” “exploratory well,” “proved developed reserves,” “proved reserves,” “proved undeveloped reserves,” “reliable technology,” “reserves,” and “resources” are defined by the Securities and Exchange Commission (the "SEC").
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COMMONLY USED DEFINED TERMS
As used in this Annual Report on Form 10-K, unless we indicate otherwise, the following terms have the following meanings:
| • | "common units” refers to common units representing limited partner interests in New Source Energy Partners L.P.; |
| • | “IPO Properties” refers to the properties, producing wells, and related oil and natural gas interests that were contributed to us by New Source Energy in connection with our initial public offering; |
| • | “MCE Entities” refers collectively to MCE, LP and MCE GP, LLC, the entities we acquired in November 2013; |
| • | “New Dominion” refers to New Dominion, LLC, the entity that serves as our contract operator and provides certain operational services to us; |
| • | “New Source Energy” 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; |
| • | “New Source Group” collectively refers to New Source Energy, New Dominion and Scintilla; however, when used in the context of the development agreement described herein, the New Source Group refers to the parties (other than us) party thereto; |
| • | “our general partner” refers to New Source Energy GP, LLC, our general partner; |
| • | “our management,” “our employees,” or similar terms refer to the management and personnel of our general partner, who perform managerial and administrative services on behalf of us. During 2013, this management and personnel performed these tasks through New Source Energy under an omnibus agreement among us, our general partner and New Source Energy; |
| • | “Scintilla” refers to Scintilla, LLC, the entity from which New Source Energy acquired substantially all of its assets in August 2011; and |
| • | “we,” “our,” “us,” and like terms refer collectively to New Source Energy Partners L.P. and its subsidiaries. |
| • | "Greater Golden Lane" includes the core Golden Lane area in which the IPO Properties are located and incorporates the adjacent townships to the north and east of the initial six townships in the core Golden Lane area. |
| • | "Deylau" refers to Deylau, LLC, of which Kristian B. Kos is the sole member. |
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CAUTIONARY STATEMENTS REGARDING FORWARD LOOKING STATEMENTS
The information discussed in this Annual Report on Form 10-K includes “forward-looking statements.” These forward-looking statements are identified by their use of terms and phrases such as “may,” “expect,” “estimate,” “project,” “plan,” “believe,” “intend,” “achievable,” “anticipate,” “continue,” “potential,” “should,” “could,” and similar terms and phrases. All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, potential increases in oil and natural gas production, the number of anticipated wells to be drilled after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:
| • | our ability to replace oil and natural gas reserves; |
| • | declines or volatility in the prices we receive for our oil, natural gas and NGLs; |
| • | our financial position; |
| • | our ability to generate sufficient cash flow and liquidity from operations, borrowings or other sources to enable us to pay our obligations and maintain our non-operated acreage positions; |
| • | future capital requirements and uncertainty of obtaining additional funding on terms acceptable to us; |
| • | our ability to finance equipment, working capital and capital expenditures; |
| • | there are significant interlocking relationships between us and the New Source Group, and there can be no assurance that these interlocking relationships may not result in conflicts of interest and other risks to decision-making actions by our officers and directors in the future; |
| • | our ability to continue our working relationship with the New Source Group; |
| • | general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business; |
| • | economic downturns may adversely affect consumption of oil and natural gas by businesses and consumers; |
| • | the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs; |
| • | uncertainties associated with estimates of proved oil and natural gas reserves and various assumptions underlying such estimates; |
| • | our ability to successfully acquire additional working interests through the efforts of the New Source Group in forced pooling processes; |
| • | the impact of environmental, health and safety, and other governmental regulations and of current or pending legislation; |
| • | environmental risks; |
| • | geographical concentration of our operations; |
| • | constraints imposed on our business and operations by our revolving credit facility and our ability to generate sufficient cash flows to repay our debt obligations; |
| • | availability of borrowings under our revolving credit facility; |
| • | drilling and operating risks; |
| • | exploration and development risks; |
| • | competition in the oil, natural gas and oilfield services industries; |
| • | increases in the cost of drilling, completion and gas gathering or other costs of production and operations; |
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| • | the inability of the New Source Group to successfully drill wells on our properties that produce oil or natural gas in commercially viable quantities; |
| • | failure to meet the proposed drilling schedule on our properties; |
| • | adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities; |
| • | drilling operations and adverse weather and environmental conditions; |
| • | limited control over non-operated properties; |
| • | reliance on a limited number of customers; |
| • | management’s ability to execute our plans to meet our goals; |
| • | our ability to retain key members of our management and key technical employees; |
| • | a shortage of qualified workers; |
| • | conflicts of interest with regard to our directors and executive officers; |
| • | access to adequate gathering systems and pipeline take-away capacity to execute our drilling program; |
| • | marketing and transportation constraints in the Hunton formation in east-central Oklahoma; |
| • | our ability to sell the oil and natural gas we produce at market prices; |
| • | costs associated with perfecting title for mineral rights in some of our properties; |
| • | title defects to our properties and inability to retain our leases; |
| • | federal, state, and tribal regulations and laws; |
| • | our current level of indebtedness and the effect of any increase in our level of indebtedness; |
| • | risks relating to potential acquisitions and the integration of significant acquisitions; |
| • | volatility of oil, natural gas and NGL prices and the effect that lower prices may have on our net income and unitholders’ equity; |
| • | a decline in oil or natural gas production or oil, natural gas or NGL prices and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital; |
| • | the effect of seasonal factors; |
| • | lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oilfield services; |
| • | further sales or issuances of common units; |
| • | accidental damage to or malfunction of equipment; |
| • | costs of purchasing electricity and disposing of saltwater; |
| • | continued hostilities in the Middle East and other sustained military campaigns or acts of terrorism or sabotage; and |
| • | other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact our businesses, operations or pricing. |
Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in “Item 1A - Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Annual Report on Form 10-K and speak only as of the date of this Annual Report on Form 10-K. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.
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PART I.
| ITEM 1. | BUSINESS |
Overview
We are a Delaware limited partnership formed in October 2012 by New Source Energy to own and acquire oil and natural gas properties in the United States. In November 2013, we acquired an oil field services business, and now we report our results of operations and describe our business 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.
Exploration and Production. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation, a conventional resource reservoir located in east-central Oklahoma. This formation has a 90-year history of exploration and development and thousands of wellbore penetrations that have led to more accurate geologic mapping.
As of December 31, 2013, we had proved reserves of approximately 20.6 MMBoe, of which approximately 60.5% were classified as proved developed reserves. Of those proved developed reserves, 73.8% were comprised of oil and natural gas liquids, or "NGLs," and 26.2% was natural gas. Of the proved developed reserves, 57.8% were proved developed producing and 2.7% were proved developed non-producing. As of December 31, 2013, we had 124,759 gross (54,989 net) acres, of which 9,079 gross (3,230 net) acres were undeveloped. As of December 31, 2013, we had 161 gross (40.1 net) proved undeveloped drilling locations, of which 60 gross (21.6 net) were infill drilling locations.
Since our initial public offering, or IPO, we have made four acquisitions of oil and natural gas properties from members of the New Source Group with aggregate estimated proved reserves of 5.5 MMBoe as of December 31, 2013, and an additional third-party acquisition of oil and gas properties with 0.5 MMBoe estimated proved reserves as of December 31, 2013. During the year ended December 31, 2013, our average net daily production was approximately 3,658 Boe/d.
Oilfield Services. We operate an oilfield services business headquartered in Oklahoma City, Oklahoma, and offer full service blowout prevention installation and pressure testing services throughout the Mid-Continent region, South Texas and West Texas, along with the provision of certain ancillary equipment necessary to perform such services. Our oilfield services business generated $23.6 million of revenue during the year ended December 31, 2013, and contributed $3.7 million of revenue to us from November 12, 2013 (the acquisition date) to December 31, 2013. For more details regarding each such acquisition, see “Acquisitions.”
Our Initial Public Offering
On February 13, 2013, we completed our initial public offering of 4,000,000 common units representing limited partner interests in the Partnership at $20.00 per common unit for total net proceeds of $71.6 million. Our common units are traded on the New York Stock Exchange under the symbol “NSLP.” On March 8, 2013, the underwriters exercised in part their over-allotment option to purchase an additional 250,000 common units. We received total net proceeds from the exercise of the underwriters’ over-allotment option of $4.65 million. In connection with the IPO, New Source Energy contributed to us certain properties, producing wells, and related oil and natural gas interests. In exchange, we assumed approximately $70.0 million of New Source Energy’s indebtedness that burdened the IPO Properties, and used a portion of the IPO net proceeds to repay in full such assumed debt at the closing of the IPO. We used $0.8 million of the remaining net proceeds, together with $15.0 million of borrowings under our revolving credit facility, to make a distribution to New Source Energy as consideration (together with our issuance to New Source Energy of 777,500 common units, 2,205,000 subordinated units and a $25.0 million note payable) for the contribution by New Source Energy of the IPO Properties and certain commodity derivative contracts. The remaining net proceeds were used for general partnership purposes.
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Ownership of our General Partner
On March 15, 2013, our general partner amended its limited liability company agreement to restructure the ownership interests among its existing owners. As of December 31, 2013, our general partner is owned 69.4% by an entity controlled by Kristian B. Kos, the President and Chief Executive Officer and a director of our general partner, 25% by an entity controlled by David J. Chernicky, the Chairman of the board of directors of our general partner, and 5.6% by New Source Energy.
Acquisitions
March Acquisition
On March 29, 2013, we completed an acquisition, with an effective date of March 1, 2013, of certain oil and gas properties located in Oklahoma ("the "March Acquired Properties") from New Source Energy, Scintilla, and W.K. Chernicky, LLC, (an Oklahoma limited liability company) for an aggregate adjusted price of $28.0 million. As consideration for the properties, we issued an aggregate of 1,378,500 common units valued at $20.30 for total consideration valued at $28.0 million. The properties are located in the Golden Lane field, where our existing properties are located, and in the Luther field, which is adjacent to the Golden Lane field. These properties had estimated proved reserves of 3.2 MMBoe as of December 31, 2013, of which 60% were proved developed, 6% were oil, 64% were NGLs and 30% were natural gas. This transaction was unanimously approved by the board of directors of our general partner, based on the approval and recommendation of its conflict committee.
May Acquisition
On May 31, 2013, we completed an acquisition of certain oil and gas properties located in Oklahoma ("the May Acquired Properties") from New Source Energy, with an effective date of May 1, 2013. As consideration for the properties, we paid a total of $8.1 million in cash to New Source Energy, but after purchase price adjustments the total consideration was $7.9 million. The properties are also located in the Greater Golden Lane field and had estimated proved reserves of 820 MBoe as of December 31, 2013, of which 1% were oil, 63% were NGLs and 36% were natural gas. This transaction was unanimously approved by the board of directors of our general partner, including each member of its conflicts committee.
July Acquisition
On July 23, 2013, we completed an acquisition of a 10% working interest in certain oil and gas properties located in Oklahoma ("the July Scintilla Acquired Properties") from Scintilla, with an effective date of May 1, 2013. As consideration for the working interest in the properties, we paid a total of $4.9 million in cash to Scintilla after purchase price adjustments. The properties are located in the Greater Golden Lane field and, based on our working interest, we acquired estimated proved reserves of 266.5 MBoe as of December 31, 2013, of which 7% were oil, 60% were NGLs and 33% were natural gas. This transaction was unanimously approved by the board of directors of our general partner, including each member of its conflicts committee.
Orion Acquisition
On July 25, 2013 the Partnership acquired certain oil and natural gas properties from Orion Exploration Partners, LLC, located in Oklahoma (the "Orion Acquired Properties"), with an effective date of May 1, 2013. The Partnership paid $3.2 million in cash for the Orion Acquired Properties after purchase price adjustments. The properties are located in the Greater Golden Lane field and, based on our working interest, we acquired estimated proved reserves of 543 MBoe as of December 31, 2013, of which 1.5% were oil, 62.4% were NGLs and 36.1% were natural gas. This transaction was unanimously approved by the board of directors of our general partner.
Southern Dome Acquisition
On October 4, 2013, we completed an acquisition (the "Southern Dome Acquisition") of working interest in 25 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma (the "Southern Dome Acquired Properties") from Scintilla, with an effective date of August 1, 2013. As consideration for the working interest, we paid $5.0 million in cash to Scintilla at closing and issued 414,045 common units with a fair market
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value of $20.79 or $8.6 million to Scintilla in November 2013. We also agreed to provide additional consideration ( the "Southern Dome Contingent Consideration") to Scintilla in November 2014 if our production attributable to the Southern Dome Acquisition for the nine-month period ending September 30, 2014 exceeds the average daily production of 383.5 Boe/d during the period between January 1, 2014 and September 30, 2014, which had an estimated fair value of $1.6 million on the acquisition date and considered part of the purchase price, for a total consideration of $14.5 million after purchase price adjustments. The estimated fair value of the Southern Dome Contingent Consideration is $0 as of December 31, 2013. We may satisfy any such additional consideration in cash, common units, or a combination thereof at our discretion. Based on our working interest, we acquired estimated proved reserves of 1.2 MMBoe as of December 31, 2013, of which 42% were oil, 13% were NGLs and 45% were natural gas. This transaction was unanimously approved by the board of directors of our general partner, including each member of its conflicts committee.
MCE Acquisition
On November 12, 2013, we acquired an oilfield services business from MCE, LLC ("MCE Acquisition"). Through our oilfield services business, we offer full service blowout prevention installation and pressure testing services throughout the Mid-Continent region, along with the provision of certain ancillary equipment necessary to perform such services. This equipment includes, but is not limited to, spacer spools, double-studded adapters, blowout preventers, ram blocks, choke manifolds, accumulators and other various pressure components. In addition to our presence in the Mid-Continent region, we recently opened field offices in South Texas to focus on the Eagle Ford Shale and in West Texas to focus on the Permian Basin. We believe that the permitting and drilling activity in both regions offer significant opportunities to expand our customer base and grow our oilfield services segment.
Aggregate consideration to acquire the oilfield services business was approximately $43.6 million, which consisted of approximately $3.8 million in cash and 1,847,265 common units. We also agreed to issue 99,768 common units, valued at $21.55 per common unit to certain employees under our long-term incentive plan, for aggregate total consideration of approximately $45.7 million. In addition, we agreed to provide additional consideration in the form of common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of the business we acquired for the nine-month period ending March 31, 2015, which is subject to a $120 million cap.
Our oilfield services segment generated $23.6 million of total revenue during the year ended December 31, 2013 and the segment contributed $3.7 million of our total revenue to the Partnership from November 12, 2013 (the acquisition date) to December 31, 2013.
Kristian B. Kos, the President and Chief Executive Officer and a director of our general partner, was an owner of the MCE Entities prior to the MCE Acquisition. The conflicts committee of the board of directors of our general partner, which, at the time, consisted of two independent directors, reviewed the MCE Acquisition and related terms and agreements, engaged and consulted with independent financial and legal advisors with respect thereto, and granted “special approval” under our partnership agreement with respect to the contribution agreement governing the MCE Acquisition. This transaction was unanimously approved by the board of directors of our general partner, based on the approval and recommendation of its conflicts committee.
Recent Developments
On January 31, 2014, we completed an acquisition of working interest in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma from CEU Paradigm, LLC. The working interest generated average daily production of approximately 490 Boe per day during the year ended December 31, 2013, of which 51% were natural gas, 34% were oil and 15% were NGLs.
As consideration for the working interest, we paid $6.9 million in cash to the seller at closing and issued 488,667 common units, valued at $23.51 per common unit, to the seller. We also agreed to provide additional consideration to the seller in November 2014 if the production attributable to the working interest for the nine-month period ending September 30, 2014 exceeds 490 Boe/d. The amount of the additional consideration, if any will be calculated as the acquisition value of the production increase (applying the same valuation methodology used to determine the initial consideration) less (i) the 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 that were not producing in paying quantities as of the effective date of the acquisition. We may satisfy any such additional consideration in cash, common units, or a combination thereof at our discretion.
Our Hedging Strategy
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Our hedging strategy includes entering into commodity derivative contracts covering approximately 50% to 90% of our estimated total production over a three-to-five year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. As opposed to entering into commodity derivative contracts at predetermined times or on prescribed terms, we intend to enter into commodity derivative contracts in connection with material increases in our estimated reserves and at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Additionally, we may take advantage of opportunities to modify our commodity derivative portfolio to change the percentage of our hedged production volumes when circumstances suggest that it is prudent to do so.
Our commodity derivative contracts may consist of natural gas, oil and NGL financial swaps, put options 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.”
Our Relationship with the New Source Group
New Source Energy is controlled by its principal stockholder, chairman and senior geologist, David J. Chernicky. David J. Chernicky owns approximately 89% of New Source Energy’s outstanding common stock, and all of the membership interests in New Dominion and Scintilla as of December 31, 2013. David J. Chernicky has historically acquired oil and natural gas properties through Scintilla, and New Dominion has acted as the operator for properties held by Scintilla for over 12 years, completing and economically producing more than 98% of all wells New Dominion has drilled in the Hunton Formation. New Source Energy acquired substantially all of its assets from Scintilla in August 2011. As of December 31, 2013, David J. Chernicky and entities he controls, including New Source Energy, collectively held (i) 30.6% of our general partner (ii) 28% of our then outstanding 9,599,578 common units and (iii) 100% of our 2,205,000 subordinated units.
Our 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:
| • | Develop Existing Proved Undeveloped Inventory. As of December 31, 2013, our oil and natural gas properties, most of which were produced from the Hunton formation, included 8.2 MMBoe of estimated proved undeveloped reserves through 161 gross (40.1 net) proved undeveloped drilling locations, of which 60 gross (21.6 net) were infill drilling locations. New Dominion, our contract operator, drilled 28 gross (10.6 net) wells during the year ended December 31, 2013. |
| • | Reduce Exposure to Commodity Price Risk and Stabilize Cash Flow Through Commodity Hedging Policy. We are party to commodity derivative contracts covering approximately 42% of our estimated oil, natural gas and NGL production from our proved undeveloped reserves as of December 31, 2013 for the years ending December 31, 2014, 2015 and 2016, based on production estimates contained in our reserve report as of December 31, 2013. Our hedging strategy includes entering into commodity derivative contracts covering approximately 50% to 90% of our estimated total production over a three-to-five year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. |
| • | Continue to Leverage Strategic Relationship with the New Source Group. We intend to continue maximizing the benefits of our relationship with the New Source Group to help control our costs, access existing infrastructure at what we believe are favorable rates and acquire producing oil and natural gas properties that meet our acquisition criteria. Since the closing of our initial public offering, we have made four acquisitions of oil and natural gas properties from members of the New Source Group, and we believe that additional transactions are possible in the future. We may also have the opportunity to work jointly with New Source Energy to pursue certain acquisitions of oil and natural gas properties. |
| • | Pursue Accretive Third Party Acquisitions of Long-Lived, Low-Risk, Producing Properties. Independent of the New Source Group, we intend to pursue acquisitions of third-party producing properties. We will pursue additional acquisition opportunities when we believe we possess a strategic or technical advantage due to our existing liquidity, operational experience and access to infrastructure. We believe that the knowledge and |
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experience of the MCE Entities’ management team, and the customer base they developed at the MCE Entities will be advantageous to us in our pursuit of future acquisition opportunities and will facilitate our expansion into other resource plays where the MCE Entities operate.
| • | Pursue Accretive Third Party Acquisitions and Expand Organically at MCE. We intend to pursue accretive acquisitions of third-party oilfield services companies that we believe would complement the MCE Entities’ operations. Additionally, we intend to expand organically at MCE by expanding into new geographic regions and new service lines for which we believe we have the expertise to gain market share. |
Specialized Processes
We, through the New Source Group, use proven methods, mechanical assistance and other specialized processes to produce still-remaining reserves from conventional oil and liquids-rich resource plays previously deemed not prospective by others. Our success comes from understanding the reservoir characteristics, and in conjunction with the New Source Group, using the latest available drilling, completion, and production technology to create natural conductive flow paths that enable access to the hydrocarbons within. This advanced recovery technique makes it highly economic to produce from these reservoirs. Along with horizontal and directional drilling, high-volume electric submersible pumps are used in our wells to reduce the hydrostatic pressure in the reservoir and pull water, gas and oil from source rock formations in a way that enables those formations to produce oil and liquids-rich natural gas. 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.
We believe we have the potential to develop a new class of large-scale reservoir systems. Other reservoirs with high water saturation have been identified in the regions in which we currently operate, and we believe they exist in many other areas in which hydrocarbons have customarily been produced. Large reservoirs previously thought to be too high in water saturation to produce potentially can be opened up to full-scale development involving the drilling and completion of hundreds of wells in a reservoir that can cover thousands of square miles.
Unlike typical oil and natural gas reservoirs, which show declining oil and gas production rates with time, this type of reservoir increases its oil and natural gas production rate over an initial period, and then, as the reservoir is depressurized, the wells assume a more typical decline curve.
Our conventional resource plays
The type of conventional resource play on which we focus is a high water saturation hydrocarbon reservoir that demonstrates characteristics of both a conventional reservoir and a resource play. The reservoir is typically made of carbonate or deltaic sand deposits. In these reservoirs, the porosity and permeability are not well connected vertically in the formation, which restricts the movement of fluid vertically through the reservoir. However, these reservoirs have good horizontal permeability and porosity that usually extends over a large area. In addition, the permeability in both directions often is enhanced by numerous naturally occurring fracture systems.
These types of reservoirs are composed of hydrocarbon accumulations in strata that have “shows” of oil, but the reservoirs typically have been deemed not prospective by others due primarily to having water saturations of 35 to 99 percent. Although the reservoir is saturated with water, there often are significant hydrocarbons present and suspended within the reservoir by the hydrostatic pressure. Conventional resource reservoirs are located around and below the conventional reservoir, though they can exist independently. This zone is a continuous hydrocarbon system over a contiguous geographical area that can be very large. Conventional resource plays are regional in extent and exhibit low risk with consistent results and predictable recoveries.
Development of our conventional resource plays
The New Source Group’s technical staff has developed geologic and engineering expertise in the areas of production phase identification, well design for horizontal drilling, strategic submersible pump placement, and product separation with disposal processes. We believe this experience helps us to understand the characteristics of and obtain efficiencies in production from the conventional resource plays on which we focus.
The New Source Group uses mapping and seismic workstation capabilities to manage large volumes of digital data to correlate key reservoir parameters. This allows the technical staff to process large volumes of geological and geophysical
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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, NGLs, natural gas, and water, and maximizing recovery through well placement to optimize the effect of wells working in concert. |
The majority of the hydrocarbons remain locked in the reservoir for up to six months after a well is completed and brought online. During this time fluids in the naturally occurring fractures are vacated utilizing electric submersible pumps, allowing the hydrostatic pressure in the reservoir to be lowered, which in turn enables the hydrocarbons to expand and vacate the pores in which they are trapped. It is at this time that peak production rates, which can average over 200 Boe per day, are observed and sustained for periods typically in excess of twelve months. During the latter stages of the well life, the electric submersible pumps are replaced with beam pumps that are less expensive to operate and maintain resulting in additional cost efficiencies.
As the formation is depressurized, the Btu content of the hydrocarbon production stream increases. Over the life of the well this creates greater volumes of condensate and NGLs per Boe produced.
The decline of saltwater volumes produced is similar to the decline of hydrocarbon production following the peak production period. This reduces operating costs over time, in turn extending the economic life of the well and maximizing the hydrocarbon recovery from the reservoir.
Our method of hydrocarbon production from conventional resource reservoirs is predicated on evaluating the optimal way to create laminar flow from the reservoir. By establishing an appropriate flow rate, the reservoir pressure drops to a point that allows for the maximum release of hydrocarbons in place. The New Source Group historically has been successful with infill drilling based on its evaluation of appropriate wellbore placement in order to create the best flow rates for reservoir drainage. In conjunction with the New Source Group, we will continuously evaluate our drilling program to select the types and spacing of wells to be drilled in order to optimize our flow rates and maximize the recovery of hydrocarbons from the Hunton reservoir. Based on our analysis to date, as of December 31, 2013, we have identified 161 gross (40.1 net) proved undeveloped drilling locations for prospective development.
Forced pooling process
Under Oklahoma law, if a party proposes to drill the initial well to a particular formation in a specific drilling and spacing unit but cannot obtain the agreement of all other oil and natural gas interest holders and other leaseholders within the unit as to how the unit should be developed, the party may commence a “forced pooling” process. In a forced pooling action, which is common in Oklahoma, the proposed operator files an application for a pooling order with the Oklahoma Corporation Commission and names all other persons with the right to drill the unit as respondents. The proposed operator is required to demonstrate in an administrative proceeding that it has made a good faith effort to bargain with all of the respondents prior to filing its application. The fair market value of the mineral interests in the unit is determined in the administrative proceeding by reference to market transactions involving nearby oil and natural gas rights, especially what has been paid for mineral leases in the particular drilling and spacing unit and the immediately surrounding drilling and spacing units.
Assuming the application is granted and a forced pooling order is granted, the respondents then have 20 days to elect either to participate in the proposed well or accept fair market value for their interest, usually in the form of a cash payment, an overriding royalty, or some combination, based on the fair market value established and approved through the administrative hearing. The pooling order usually also addresses the time frame for drilling the well and provides for the manner in which future wells within the unit may be drilled. The applicant for the pooling order is ordinarily designated as the operator of the wells subject to the pooling order.
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The availability of forced pooling means that it normally is difficult for a small number of owners to block or delay the drilling of a particular well proposed by another interest holder. Exploration and production companies in Oklahoma often negotiate to lease as much of the mineral interests in a particular area as are readily available at acceptable rates, and then use the forced pooling process to proceed with the desired development of the well. In this manner, through the efforts of the New Source Group, we have the ability to expand into and develop areas near our existing acreage even if we are unable to lease all of the mineral interests in those areas.
The New Source Group’s experience has been that very few other interest owners elect to participate in the drilling of new wells in our area of operations. The New Source Group has drilled a total of 70 wells over the three years ended December 31, 2013 in the areas of mutual interest defined by the Golden Lane Participation Agreement through successful forced pooling efforts. On average, the collective working interest of third party owners of mineral rights in these drilling units who have elected to participate in these wells (excluding participation by the other parties to the Golden Lane Participation Agreement) has been less than 1%. We believe this is attributable primarily to a disinclination on the part of such third party owners to bear their share of the costs of the proposed well. Assuming this trend continues, we expect we will be able to use the forced pooling process to increase our relative working interest in wells in which we elect to participate and that we have a right to in our agreements, which would lead to a proportionate increase in our share of the production and reserves associated with any such well. For this reason and assuming a well in which we participate is successfully drilled and completed on a particular proved undeveloped drilling location, we believe our proved developed reserves associated with such well likely will exceed the proved undeveloped reserves previously estimated to relate to our interest in such proved undeveloped drilling location.
Our Operating Segments
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. For financial information about our segments, including revenue from external customers and total assets by segment, see “Note 15 - Segment Information” in Part II, Item 8 “Financial Statements and Supplementary Data.”
Exploration and Production Segment. Our exploration and production segment focuses on non-operated exploration, development and production of the Partnership’s oil and liquids rich portfolio of properties in the Hunton formation, a conventional resource reservoir located in east-central Oklahoma. Our exploration and production segment contributed $46.9 million of revenue for the year ended December 31, 2013.
Oilfield Services Segment. Our oilfield services segment, acquired in November 2013 and headquartered in Oklahoma City, Oklahoma, offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region, South Texas and West Texas, along with the provision of certain ancillary equipment necessary to perform such services, which may include spacer spools, double-studded adapters, blowout preventers, ram blocks, choke manifolds, accumulators and other various pressure components. Our oilfield services segment contributed $3.7 million of revenue for the year ended December 31, 2013.
Principal Customers
The majority of our revenue has historically been generated by our exploration and production segment. Our principal products are crude oil, NGLs and natural gas, which are marketed and sold primarily to purchasers that have access to nearby pipeline facilities, refineries or other markets. Typically, crude oil is sold at the wellhead at field-posted prices, and NGLs and natural gas are sold both (i) under contract at negotiated prices based upon factors normally considered in the industry (such as distance from well to pipeline, pressure, and quality) and (ii) at spot prices.
We rely on our midstream partners for the transportation, marketing, sales and account reporting for all production. The New Source Group is responsible for the marketing and sales of all production to regional purchasers of petroleum products, and we evaluate the creditworthiness of those purchasers periodically. Although historically all of the natural gas, NGLs and crude oil produced from our Golden Lane field properties have been sold to a limited number of purchasers, we believe that we would be able to secure replacement purchasers if any of these purchasers were unable to continue to purchase the natural gas and crude oil produced at our properties.
Natural Gas Liquids and Natural Gas Sales/Customers: New Dominion has previously dedicated all NGLs and natural gas produced and sold from wells it operates in the Golden Lane field to Scissortail Energy, LLC, a subsidiary of Kinder
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Morgan Energy Partners (“Scissortail”), pursuant to a long-term gas sales contract entered into on May 1, 2005, between a member of the New Source Group and Scissortail. As part of the consideration for our long-term gas dedication, Scissortail constructed and owns a gas processing plant in Paden, Oklahoma, where the gas from the Golden Lane field is processed. None of these purchasers are affiliated in any way with us or David J. Chernicky. Sales to Scissortail comprised 80% of our total sales for the year ended December 31, 2013.
Crude Oil Sales/Customers: The crude oil produced from our properties is sold to third-party marketing companies, presently United Petroleum Purchasing Company (“UPP”). These contracts are presently for terms of six months or less, which is customary for oil sales contracts. During the year ended December 31, 2013, 100% of total oil production from our properties in the Golden Lane field was sold to UPP, which is not affiliated in any way with us or David J. Chernicky. Sales to UPP comprised 14% of our total sales for the year ended December 31, 2013.
Oilfield Services Customers: The addition of oilfield services segment in November 2013 expanded our customer base, thereby somewhat reducing our overall customer concentration. We had sales totaling greater than 10% of total sales to two unrelated parties comprising 24% and 14%, of total sales, respectively for the period November 12, 2013 (acquisition date) through December 31, 2013. However, given the significance of our exploration and production segment to us, our revenue, earnings and cash flow are still substantially dependent upon our concentrated oil and natural gas customers.
Competition
We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small 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.
Our ability to grow our oilfield services business will depend 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 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.
Since blowout preventers are paramount for the safety of the field personnel and the environment of drilling locations, they must be tested and inspected on a regular basis. As of December 31, 2013 approximately 70% of revenue generated by our oilfield services segment was attributable to installation and pressure testing with the remaining 30% of revenue attributable to providing various auxiliary equipment that complements the blowout preventer. Virtually all of the segment’s revenue is derived from the U.S. land market areas. Demand for these services can change quickly, and is primarily dependent on the number of wells drilled and completed. The segment has established operations in the central Mid-Continent region, the west Texas Permian Basin, and the Eagle Ford shale of south Texas as a means to lessen exposure to localized volatility in drilling activity by having a footprint in various geographic basins.
Certain Agreements Governing Our Operations
Development Agreement with the New Source Group
We are party to a development agreement with the New Source Group with respect to the drilling of our proved undeveloped reserves that comprise a portion of 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. In connection with our entry
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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.”
Additionally, beginning with the first quarter of 2014 and continuing through the fourth quarter of 2016, if our average production declines below 3,200 Boe/d for any preceding four quarter period, then holders of our subordinated units will not be entitled to receive the quarterly distributions otherwise payable on our subordinated units for such quarter. We expect that any funds not distributed to holders of our subordinated units will be reserved by the board of directors of our general partner for use in growing our production.
While we have committed to establishing a maintenance drilling budget averaging no less than $8.2 million annually from 2014 through 2016 pursuant to the development agreement, we anticipate that our general partner will propose, not less than annually, additional growth capital expenditures and related drilling and development projects to grow our resources and production over time. We expect this growth to come through drilling additional proved undeveloped properties, increasing our working interests in wells through forced pooling and acquiring properties from both New Source Group and third parties. The amount and timing of these growth capital expenditures will depend on both the amount of capital we have available to fund such expenditures as well as the success of our drilling program.
Pursuant to the development agreement, our general partner, at least annually and likely more frequently, at its discretion, determines our maintenance drilling budget. Our general partner also has the right to propose which wells are drilled based on our maintenance drilling budget. Under the development agreement, New Dominion is obligated to use its commercially reasonable best efforts to (i) conduct its operations such that the Partnership’s proportionate share of capital expenses that we would consider maintenance capital under the Golden Lane Participation Agreement is equal to the annual maintenance drilling budget set by our general partner and (ii) cause the wells drilled pursuant to the Golden Lane Participation Agreement to be consistent with the maintenance drilling schedule proposed by our general partner. Our general partner also has the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.
Golden Lane Participation Agreement
The Golden Lane Participation Agreement controls the development and operation of the Golden Lane field and provides New Dominion, as operator, with authority to control the development and operation of the field. New Dominion’s control rights are subject to its agreement to use its commercially reasonable efforts to conduct its operations in a manner consistent with the development agreement described below. New Dominion is empowered to acquire additional leasehold within the Golden Lane field for the account of the working interest owners in exchange for a turnkey fee per net acre acquired. This turnkey fee is currently $300 per net acre acquired and may be increased by New Dominion from time to time in the event of an increase in prevailing leasehold acquisition costs. The Golden Lane Participation Agreement permits New Dominion to hold record title to any undeveloped leasehold within the Golden Lane area of mutual interest that it acquires in the future for the benefit of the parties to the Golden Lane Participation Agreement until such time as development of the applicable leasehold commences. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold for a turnkey acreage fee then applicable under the Golden Lane Participation Agreement until development has commenced. Although New Dominion would hold record title to any such undeveloped leasehold, the Golden Lane Participation Agreement requires the assignment to us of the leasehold when development commences, and it is this right on which we will rely in connection with estimating any proved undeveloped reserves associated with such acreage hereafter acquired by New Dominion for our benefit in our future reserve reports. Each party to the Golden Lane Participation Agreement has committed to participate in future wells proposed by the operator for its proportionate share of the costs associated with such wells. The parties also have agreed to pay New Dominion their proportionate shares of an initial connection charge of $300,000 per well in the Golden Lane field, subject to increase in certain circumstances, for connection and access to its saltwater disposal infrastructure within the Golden Lane field and also to pay New Dominion their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.
In the event that New Dominion acquires additional leasehold acreage for the benefit of the parties to the Golden Lane Participation Agreement (including by means of forced pooling) and subsequently commences development, New Dominion will assign record title to the other parties to the Golden Lane Participation Agreement in their proportionate share. In connection with any such assignment, New Dominion will retain an overriding royalty interest in an amount equal to 20% 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
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ownership within such drilling and spacing unit shall be proportionately reduced in any assignment pursuant to the Golden Lane Participation Agreement. Further, if New Dominion is unable to acquire all depths and formations attributable to a particular lease, then the proportionate share of each of the parties with respect to such lease included within any assignment pursuant to the Golden Lane Participation Agreement shall be limited to only those depths and formations so acquired by New Dominion.
The Golden Lane Participation Agreement requires us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. The Golden Lane Participation Agreement contains significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements, as is customary in the oil and natural gas industry. If a party declines to participate in a new well that New Dominion proposes, such party will not be eligible to participate in the next four wells in adjacent drilling and spacing units to such proposed well (unless the proposed well is in an undrilled township and range, in which case such party will not be eligible to participate in the next eight wells in adjacent drilling and spacing units to the proposed well), and such party also would be obligated to pay for its share of the applicable acquisition costs associated with the leasehold interests underlying the proposed new well even though it has elected not to participate in the well and the associated costs themselves. In addition, if a party declines to participate in a new well that New Dominion proposes, such party will relinquish its interest in the new well and its share of production from the new well until such time at which the proceeds from such relinquished interest paid to the working interest owners that elected to participate in the new well reach specified aggregate thresholds intended to compensate the parties for the election not to participate. The Golden Lane Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs within thirty days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs later.
In return for serving as the operator of the Golden Lane field, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Golden Lane Participation Agreement, including allocable shares of its employees and certain other general and administrative expenses, under joint account procedures common in the oil and natural gas industry. We generally are required to pay our proportionate share of these ongoing costs associated with the operation of our wells on a monthly basis and within thirty days of the date of New Dominion’s invoice.
Luther Joint Operating Agreement
In connection with our acquisition of certain of properties in the March Acquisition from New Source Energy and Scintilla, we succeeded to those parties’ rights and obligations under a joint operating agreement governing the Luther field, which we refer to as the “Luther JOA.” New Dominion is the 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 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 and natural gas, 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
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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 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 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 operator of the Luther field, 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 operator’s invoice.
Eight East Participation Agreement
In connection with the May Acquisition from New Source Energy and the July Acquisition from Scintilla, 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 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 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 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
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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 for wells in which we elect to participate within 30 days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs earlier.
In return for serving as the 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.
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 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 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 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
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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 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 operator or 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 operator when such costs exceed $100,000.
In return for serving as the 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.
Regulation of the Oil and Natural Gas Industry
Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes, environmental requirements, worker health and safety standards and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and that impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties, corrective action or remedial obligations and injunctions limiting or prohibiting some or all of the New Source Group’s operations on our behalf. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the oil and natural gas industry are regularly considered by Congress, state governments, the Federal Energy Regulatory Commission (“FERC”), the EPA, the CFTC and the courts. We believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. We are not currently aware of any specific pending legislation or regulation that is reasonably likely to be enacted, or for which we cannot predict the likelihood of enactment, and that is reasonably likely to have a material effect on our financial position, cash flows or results of operations.
Regulation of transportation of oil
Sales of crude oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
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Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act (the “ICA”), the Energy Policy Act of 1992 (“EPAct”) and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively referred to as “petroleum pipelines”), be just and reasonable and non-discriminatory and that such rates and terms and conditions of service be filed with FERC. EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA, which are commonly referred to as “grandfathered rates.” Pursuant to EPAct 1992, FERC also adopted a generally applicable ratemaking methodology, which, as currently in effect, allows petroleum pipelines to change their rates provided they do not exceed prescribed ceiling levels that are tied to changes in the Producer Price Index for Finished Goods (“PPI”), plus 1.3%. For the five-year period that began July 1, 2011, the index is PPI plus 2.65%.
FERC has also established cost-of-service ratemaking, market-based rates, and settlement rates as alternatives to the indexing approach. A pipeline may file rates based on its cost-of-service if there is a substantial divergence between its actual costs of providing service and the rate resulting from application of the index. A pipeline may charge market-based rates if it establishes that it lacks significant market power in the affected markets. Further, a pipeline may establish rates through settlement with all current non-affiliated shippers. Shippers also may challenge rates before FERC.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory, common carrier basis. Under this standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
Regulation of transportation and sales of natural gas
FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affect the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ traditional role of providing the sale and transportation of natural gas as a single service has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity for a two-year experimental period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. FERC has now permanently lifted the ceiling on short-term releases and adopted regulations that facilitate the use of asset managers to manage pipeline capacity.
Gathering services, which occur upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities is done on a case by case basis. To the extent that FERC issues an order which reclassifies transmission facilities as gathering facilities, and depending on the scope of that decision, our costs of getting gas to point of sale locations may increase. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not
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generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Oklahoma, where all of our properties are presently located, and other states have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, most states, including Oklahoma, impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within their jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Market transparency rules
In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Pursuant to Order No. 704, wholesale buyers and sellers of annual quantities of 2.2 million MMBtu or more of natural gas in the previous calendar year, including intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, by May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. Some of our operations may be required to comply with Order No. 704’s annual reporting requirements.
In 2008, the FERC issued Order No. 720, which increases the Internet posting obligations of interstate pipelines, and also requires “major non-interstate” pipelines (defined as pipelines that are not natural gas companies under the Natural Gas Act that deliver more than 50 million MMBtu annually and including gathering systems) to post on the Internet the daily volumes scheduled for each receipt and delivery point on their systems with a design capacity of 15,000 MMBtu per day or greater. Numerous parties requested modification or reconsideration of this rule. An order on rehearing, Order No. 720-A, was issued on January 21, 2010. In that order FERC reaffirmed its holding that it has jurisdiction over major non-interstate pipelines for the purpose of requiring public disclosure of information to enhance market transparency. Order No. 720-A also granted clarification regarding application of the rule. In October 2011, the Fifth U.S. Circuit Court of Appeals vacated the order with respect to major non-interstate pipelines.
In May 2010, the FERC issued Order No. 735, which requires intrastate pipelines providing transportation services under Section 311 of the Natural Gas Policy Act of 1978 and “Hinshaw” pipelines operating under Section 1(c) of the Natural Gas Act to report on a quarterly basis more detailed transportation and storage transaction information, including: rates charged by the pipeline under each contract; receipt and delivery points and zones or segments covered by each contract; the quantity of natural gas the shipper is entitled to transport, store, or deliver; the duration of the contract; and whether there is an affiliate relationship between the pipeline and the shipper. Order No. 735 further requires that such
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information must be supplied through a new electronic reporting system and will be posted on FERC’s website, and that such quarterly reports may not contain information redacted as privileged. The FERC promulgated this rule after determining that such transactional information would help shippers make more informed purchasing decisions and would improve the ability of both shippers and the FERC to monitor actual transactions for evidence of market power or undue discrimination. Order No. 735 also extends the Commission’s periodic review of the rates charged by the subject pipelines from three years to five years. In December 2010, the Commission issued Order No. 735-A. In Order No. 735-A, the Commission generally reaffirmed Order No. 735 requiring Section 311 and “Hinshaw” pipelines to report on a quarterly basis storage and transportation transactions containing specific information for each transaction, aggregated by contract anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans. In January 2012, FERC revised the reporting requirements applicable to storage.
There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. New pipeline safety legislation requiring more stringent spill reporting and disclosure obligations has been introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. In December 2011, both Houses passed bipartisan legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules. In addition, the Pipeline and Hazardous Materials Safety Administration announced an intention to strengthen its rules and recently promulgated new regulations extending safety rules to certain low pressure, small diameter pipelines in rural areas.
Environmental Matters and Occupational Safety and Health
The New Source Group’s oil and natural gas exploration, production and processing operations on our behalf 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 exploration and production industry 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 New Source Group’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 the New Source Group’s business operations are subject on our behalf and for which compliance may have a material adverse impact on New Source Group’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
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of persons considered to be responsible for the release of a “hazardous substance” into the environment, including the current and past owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In the course of its operations, the New Source Group generates materials that may be regulated as hazardous substances. In addition, the Resource Conservation and Recovery Act, as amended (“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 in the New Source Group’s costs to manage and dispose of generated wastes, which could have a material adverse effect on the New Source Group’s and our results of operations and financial position. In the course of the New Source Group’s operations, it generates some amounts of ordinary industrial wastes that may be regulated as hazardous wastes. Because of historical and/or current operating practices upon our properties by the New Source Group and/or third party predecessor owners or operators whose treatment and disposal of hazardous substances, wastes, or petroleum hydrocarbons was not under the New Source Group’s or our control, those properties may have become impacted and may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the New Source Group or we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination.
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. The operations conducted by the New Source Group on our behalf are subject to Oklahoma Corporation Commission requirements, including regulations for responding to and remediating spills. 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 U.S. Environmental Protection Agency (“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 U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under 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 the New Source Group’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 (“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 the New Source Group’s ability to dispose of produced waters and ultimately increase the cost of their and our operations, which costs could be significant.
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Hydraulic Fracturing
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 but the EPA has asserted federal regulatory authority under the SDWA over certain hydraulic fracturing involving the use of diesel fuel and issued final permitting guidance in February 2014 for hydraulic fracturing activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the federal Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and it continues to project the issuance of an Advance Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations but it does not state a deadline for such issuance. 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 the New Source Group 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. In addition, 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 the New Source Group 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 the New Source Group 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.
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. 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 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards for shale gas in 2014. Also, in May 2013, the federal Bureau of Land Management (“BLM”) published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that, if adopted, would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. 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 under the SDWA or other regulatory mechanisms.
To our knowledge, there have been no citations, suits, or contamination of potable drinking water arising from the New Source Group’s hydraulic fracturing operations. We have insurance policies in effect that are intended to provide coverage for our losses solely related to the New Source Group’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 and natural gas 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 Environmental Assessment 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, the New Source Group 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. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas 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
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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 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 the New Source Group wishes to conduct seismic surveys, development activities or abandonment operations, such work could be prohibited or delayed or expensive mitigation may be required. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service 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 could cause the New Source Group to incur increased costs arising from species protection measures or could result in limitations on New Source Group’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.
Air emissions
The federal Clean Air Act, as amended (“CAA”), and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations, through the establishment of air emissions standards and associated construction and operating permitting programs and also imposes various monitoring, testing and reporting requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of oil and natural gas projects. Covered emissions sources of the New Source Group subject to new or emerging laws or regulations restricting such air pollutants may be required to incur certain capital expenditures over the next several years, which expenditures may be significant. For example, in 2012, the EPA published final rules under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare. In addition, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors and from pneumatic controllers and storage vessels. Compliance with these requirements could increase our costs of development and production, which costs could be significant.
Climate change
Based on findings made by the EPA in December 2009 that emissions of carbon dioxide, or CO2, 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 certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. These EPA rulemakings could adversely affect the New Source Group operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of the New Source Group operations.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG
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emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact New Source Group operations and our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the New Source Group’s equipment and operations could result in increased costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with those operations, and such requirements also could adversely affect demand for the oil and natural gas that are produced by the New Source Group from our properties.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas or otherwise cause the New Source Group to incur significant costs in preparing for or responding to those effects, which development could have a significant adverse effect on our financing and results of operations.
Worker Safety and Health
In the performance of oil and natural gas exploration and production operations on our behalf, New Source Group is subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that the New Source Group organize and/or disclose information about hazardous materials used or produced in those operations and that this information be provided to employees, state and local governmental authorities and citizens. In connection with the performance of these operations, we believe that New Source Group is in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Management
We are managed and operated by the board of directors and executive officers of New Source Energy GP, LLC, our general partner. Pursuant to an omnibus agreement with New Source Energy, New Source Energy provided management and administrative services through December 31, 2013. As of January 1, 2014 our general partner provides management and administrative services that we believe are necessary to allow our general partner to operate, manage and grow our business. Some of the executive officers and/or directors of our general partner currently serve as executive officers and/or directors of members of the New Source Group. For more information about the directors and officers of our general partner, see “Item 10 - Directors, Executive Officers and Corporate Governance - Management.”
Employees
As of December 31, 2013, New Source Energy had 9 full-time employees supporting the operation of our oil and natural gas properties and our subsidiary businesses. MCE had 127 full-time employees working in the oil field services segment. 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.
Insurance Matters
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.
Available Information
Our principal executive offices are located at 914 North Broadway, Suite 230, Oklahoma City, Oklahoma 73102, and our phone number is (405) 272-3028. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”) are made available free of charge on our website at www.newsource.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file
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with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. No information from either the SEC’s website or our website is incorporated herein by reference.
| ITEM 1A. | RISK FACTORS |
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
We may not have sufficient cash to pay the minimum quarterly distribution on our common units following the establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates.
We may not have sufficient available cash each quarter to pay the minimum quarterly distribution of $0.525 per unit or any other amount. Under the terms of our partnership agreement, the amount of cash available for distribution will be reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, 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 amount of oil, natural gas and NGLs we produce; |
| • | the prices at which we sell our oil, natural gas and NGL production; |
| • | the amount and timing of settlements of our commodity derivatives; |
| • | the level of our operating costs, including maintenance capital expenditures and payments to our general partner; |
| • | the level of drilling activity and demand for our oilfield services; 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 “Item 5 - Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.”
We rely on New Source Energy and New Dominion, our contract operator, to execute our drilling program. If either New Source Energy or New Dominion fails to perform or inadequately performs, our operations will be adversely affected and our costs could increase or our reserves may not be developed, reducing our future levels of production and our cash flow from operations, which could affect our ability to make cash distributions to our unitholders.
We have entered into agreements with New Source Energy and New Dominion, under which we rely on New Dominion to operate all of our existing producing wells and coordinate our development drilling program. For example, pursuant to our development agreement with New Source Energy and New Dominion, our general partner has the ability to propose an annual drilling schedule as well as to determine our annual maintenance drilling budget. We are a party to these agreements, pursuant to which New Dominion serves as the contract operator for certain of our properties. While under the terms of the development agreement, New Dominion is required to use its commercially reasonable efforts to ensure that our proportionate share of capital costs under the Golden Lane Participation Agreement are equal to our general partner’s proposed annual maintenance budget, New Dominion has the ability to propose upward or downward revisions to that budget subject to the approval of our general partner. Similarly, while our general partner is required to establish an annual drilling schedule, New Dominion may propose additions, substitutions or deletions subject to the approval of our general partner. Changes to either the budget or the drilling schedule could 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
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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 New Dominion 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 $7.7 million, or 154%, to $12.6 million in 2013 from $5.0 million in 2012 primarily due to the acquisition of oil and gas properties and increased operator fees and vendor costs.
Producing oil and natural gas reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore our cash flow and ability to make distributions are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions.
A decline in oil, natural gas and NGL prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil, natural gas and NGLs heavily influences our revenue, profitability, access to capital and future rate of growth. Oil, natural gas and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
| • | worldwide and regional economic and political conditions impacting the global supply and demand for oil, natural gas and NGLs; |
| • | the price and quantity of imports of foreign oil and natural gas; |
| • | the level of global oil and natural gas exploration and production; |
| • | the level of global oil and natural gas inventories; |
| • | localized supply and demand fundamentals and transportation availability; |
| • | weather conditions and natural disasters; |
| • | domestic and foreign governmental regulations; |
| • | speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts; |
| • | price and availability of competitors’ supplies of oil and natural gas; |
| • | the actions of the Organization of Petroleum Exporting Countries, or OPEC; |
| • | technological advances affecting energy consumption; and |
| • | the price and availability of alternative fuels. |
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 71% of our estimated proved reserves as of December 31, 2013 were oil and NGLs 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, 2013, the daily NYMEX West Texas Intermediate oil spot price ranged from a high of $110.62 per Bbl to a low of $86.65 per Bbl, and the NYMEX natural gas Henry Hub spot price ranged from a high of $4.52 to a low of $3.08 per MMBtu.
Substantially all of our oil production is sold to purchasers under short-term (less than twelve months) contracts at market based prices. Lower oil and NGL prices and, to a lesser extent, natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. Lower commodity prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves.
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Unless we replace the oil and natural gas reserves we produce, our revenues and production will decline, which would adversely affect our cash flow from operations and our ability to make distributions to our unitholders.
We will be unable to sustain our minimum quarterly distribution without substantial capital expenditures that maintain our asset base. In general, production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our current proved reserves will decline as reserves are produced and, therefore, our level of production and cash flows will be affected adversely unless we participate in successful development activities or acquire properties containing proved reserves. Thus, our future oil and natural gas production and, therefore, our cash flow from operations are highly dependent upon the level of success we, in conjunction with the New Source Group, have in finding or acquiring additional reserves. However, we cannot assure you that our future activities will result in any specific amount of additional proved reserves or that the New Source Group will be able to drill productive wells at acceptable costs. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution to our unitholders.
According to estimates included in our proved reserve report, if on December 31, 2013 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 10.6% over 10 years. If we fail to replace reserves, our level of production and cash flows will be affected adversely. Our total proved reserves will decline as reserves are produced unless the New Source Group conducts other successful exploration and development activities or we acquire properties containing proved reserves, or both. 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 the New Source Group to develop our properties. Other than as provided in our development agreement, our ability to achieve targeted returns on capital in drilling or acquisition activities and to achieve production growth rates will be materially affected by decisions made by the New Source Group over which we have little or no control. Such decisions include:
| • | the timing of capital expenditures; |
| • | the timing of initiating the drilling and recompleting of wells; |
| • | the extent of operating costs; |
| • | selection of technology and drilling and completion methods; and |
| • | the rate of production of reserves, if any. |
Although we monitor our cost and work with New Dominion 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 $7.7 million, or 154%, to $12.6 million in 2013 from $5.0 million in 2012 primarily due to the acquisition of oil and gas properties and increased operator fees and vendor costs.
The participation agreements contain terms that may be disadvantageous to us.
In connection with our entry into the development agreement with New Source Energy and New Dominion, we became a party to the Golden Lane Participation Agreement, which includes both affiliated and third party lease holders in the Golden Lane field. While our general partner has the ability to establish our annual maintenance drilling budget and drilling schedule and New Dominion has agreed to use its commercially reasonable best efforts to comply with each, New Dominion serves as the contract operator under the terms of the Golden Lane Participation Agreement and, as among the balance of the participants in that agreement, has the sole right to propose new wells. Similarly, as the operator, New Dominion has the sole right to propose new wells under the other participation agreements. In addition, New Dominion 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 New Dominion a high degree of control over the development of the properties. Such terms include the following:
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| • | with few exceptions, New Dominion may retain record title to our interest in any undeveloped properties that New Dominion acquires in the future for our benefit until after the drilling of and production from such properties. |
| • | subject to our general partner’s approval in certain circumstances, New Dominion may substitute one or more wells intended to be drilled with a new well or add additional wells. We are obligated to pay our proportionate share of any additional costs incurred. |
| • | if we decline to participate in a new well that New Dominion proposes, we will not be eligible to participate in 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 New Dominion 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. |
| • | we are obligated to pay both a well connection fee and a fee per barrel of saltwater disposed and a proportionate share of the cost to maintain such disposal wells; however, we do not obtain any ownership rights in such disposal wells, pipelines or other infrastructure. |
| • | our annual maintenance drilling budget includes a proportionate share of the capital costs of oil, gas, water and electrical infrastructure; however, such infrastructure remains the property of our contract operator. |
| • | our contract operator may increase certain of the fees and costs charged to us. |
| • | certain costs charged to us are “turnkey” costs, which may be higher or lower than the actual costs incurred. |
| • | we may be liable for certain legacy liabilities related to the 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 any 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.
If our contract operator fails to perform its obligations under its agreements with us, becomes subject to bankruptcy proceedings or otherwise proves to be an undesirable operator, our business could be adversely affected.
The successful execution of our strategy depends on continued utilization of New Dominion’s oil and gas infrastructure and technical staff as the operator of our properties. Failure to continue this relationship through (i) the termination or expiration of the operating agreements governing such relationship, or New Source Energy’s other arrangements with New Dominion and its affiliates or (ii) the bankruptcy or dissolution of New Dominion could have a material adverse effect on our operations and our financial results. In particular, if New Dominion becomes subject to bankruptcy proceedings, New Dominion or the bankruptcy trustee may be able to cancel one or more of its agreements with us on the basis that they are “executory contracts.” If this were to occur, we would be required either (i) to renegotiate with New Dominion or its successor to continue to serve as the operator of our properties and provide us with access to the saltwater disposal and other infrastructure serving our properties or (ii) to select another operator and obtain access to similar infrastructure from other sources, any of which would most likely result in higher costs to us for such services and infrastructure.
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
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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.
There are risks relating to our acquisition strategy. 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 technologies, operations and assets that are complementary to our existing businesses. There are financial, operational and legal risks inherent in any acquisition strategy, including:
▪ increased financial leverage;
▪ ability to obtain additional financing or issue additional securities;
▪ increased interest expense 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 financial condition and results of operation. See “Business-Acquisitions” and “Business-Recent Developments.”
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 and natural gas wells, including landing the wellbore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore, fires and spills, among others. Risks in completing our wells include, but are not limited to, being able to produce the formation, being able to run tools the entire length of the wellbore during completion operations and successfully cleaning out the wellbore. The occurrence or non-occurrence, as appropriate, of any of these events could significantly reduce our revenues or cause substantial losses, impairing our future operating results. We may become subject to liability for pollution, 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.
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Our reliance on specialized processes creates uncertainties that could adversely affect our results of operations and financial condition.
One of our business strategies is to commercially develop conventional resource reservoirs using specialized processes employed by the New Source Group. One technique utilized by the New Source Group is the installation of electric submersible pumps to depressurize the targeted hydrocarbon-bearing reservoir, allowing the gas to expand and push oil and natural gas out of the pores in which they are trapped, in order to increase the production of oil and natural gas. The additional production and reserves attributable to the use of these techniques is inherently difficult to predict. If these specialized processes do not allow for the extraction of additional oil and natural gas production in the manner or to the extent that we anticipate, our future results of operations and financial condition could be materially adversely affected.
Our oilfield services business and financial performance depends on the level of drilling and completion activity in the oil and natural gas industry.
The number of rigs drilling for natural gas has recently declined as a result of low natural gas prices; however, the number of rigs drilling for oil has offset this decline as a result of relatively high prices for oil. To the extent that the recent fluctuations in global crude oil prices develop into a prolonged decline, this drop could result in a reduction in the growth rate of active oil rigs and a decline in the number of active oil rigs from current levels.
Oil and natural gas producers’ expectations for lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending. Industry conditions that impact the activity levels of oil and natural gas producers are influenced by numerous factors over which we have no control, including:
| • | governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; |
• global weather conditions and natural disasters;
• worldwide political, military, and economic conditions;
• the cost of producing and delivering oil and natural gas;
• commodity prices; and
• potential acceleration of development of alternative energy sources.
A prolonged reduction in natural gas and oil prices would 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 oilfield services we provide. In addition, any future decreases in the rate at which oil and natural gas reserves are developed, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could have a material adverse effect on our business, even in a stronger natural gas and oil price environment.
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, David J. Chernicky 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 and natural gas
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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, David J. Chernicky, 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 highly skilled engineers, geologists and highly trained technicians, 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 and gas. 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.
We rely on our relationships with affiliates to access infrastructure that is critical to the development of our assets. Adequate infrastructure may not be available at an economic rate.
Execution of our business strategy is dependent on the availability and capability of various infrastructure, including gas gathering and processing, saltwater disposal, and transportation. Future acquisitions may require us to expend significant capital to acquire, develop or access similar infrastructure. Such capital requirements may adversely impact our returns.
Access to saltwater disposal infrastructure may not be sufficient to handle all saltwater produced, and more stringent environmental regulations may impact the New Source Group’s ability to handle saltwater.
The proposed production is dependent on economically disposing of large amounts of saltwater utilizing the New Source Group’s existing saltwater disposal infrastructure. Changing, more stringent, environmental regulations or the unexpected production of excessive saltwater could render such infrastructure insufficient and require additional capital expenditures as well as result in delays in production activities.
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 crude oil and natural gas produced from these areas through transportation systems that we do not own. The lack of availability or capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties.
A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of accidents, field labor issues or strikes, or the New Source Group might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could adversely affect our cash flow from operations.
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 crude oil and natural gas reserves, which are sensitive to oil and natural gas prices and generally dependent on the industry’s view of future oil and natural gas 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 and natural gas and expectations about future prices; |
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| • | cost of producing and the ability to deliver oil and natural gas; |
| • | 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 moratoria 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 and natural gas that cannot be measured in an exact manner. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of 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
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expenses, capital expenditures, taxes and availability of funds. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production.
Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of 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 substantial portion of our estimated proved reserves is undeveloped and may not ultimately be developed or become commercially productive, which could have a material adverse effect on our future oil and natural gas reserves and production and, therefore, our future cash flow and income.
Approximately 39.5% of our total estimated proved reserves as of December 31, 2013 were proved undeveloped reserves and may not be ultimately developed or produced. In estimating our proved undeveloped reserves, we rely upon estimates of our working interest and net revenue interest based on our current ownership of leasehold in the proposed drilling unit, and we also use assumed production volumes based on production histories and geological information. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in our reserve report assumes that substantial capital expenditures are required and will be made to develop these reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the standardized measure of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved reserves as unproved reserves.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements for the years ended December 31, 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 and natural gas; |
| • | our actual development and production expenditures; |
| • | the amount and timing of actual production; and |
| • | changes in governmental regulations or taxation. |
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in 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 and natural gas reserves.
The natural gas and oil industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of oil, natural gas and NGL reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations and our revolving credit facility, 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 or a decline in commodity prices from recent levels, we would need to curtail our development activities, acquisition activities, or both, or
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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 the 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 NGLs we are able to produce and sell from existing wells; |
| • | the prices at which our oil, natural gas and NGLs are sold; |
| • | our ability to acquire, locate and produce new reserves; and |
| • | the ability of our banks to lend. |
If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower oil, natural gas or NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing.
Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital and increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
If oil, natural gas and NGL prices decrease, we may be required to take write-downs of the carrying values of our oil and natural gas properties.
We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under our revolving credit facility. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future that could have a material adverse effect on our ability to borrow under our revolving credit facility and our results of operations for the periods in which such charges are taken.
Our insurance policies might be inadequate to cover our liabilities.
Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability, and the damages are not covered by insurance or are in excess of policy limits, then our business, results of operations and financial condition may be materially adversely affected.
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Competition in the oil and natural gas industry is intense, and many of our competitors have greater resources than we do.
We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. As a relatively small 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.
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 NGLs prices. We cannot assure you that the commodity derivative contracts we have entered into, or will enter into, will adequately protect us from fluctuations in oil prices.
The enactment of derivatives legislation and regulation could have an adverse effect on our ability to use derivative instruments to reduce the negative effect of commodity price, interest rate and other risks associated with our business.
On July 21, 2010, new comprehensive financial reform legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was enacted that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Act requires the Commodities Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation.
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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.
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 and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Act is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
Our production of oil and natural gas is sold to a limited number of customers and the credit default of one of these customers could have a temporary adverse effect on us.
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 and Sun Refining. Our results of operations would be adversely affected as a result of non-performance by any of our customers. A non-payment default by one of these large customers could have an adverse effect on us, temporarily reducing our cash flow.
Increases in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.
As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions to our unitholders and the implied distribution yield. The distribution yield is often used by investors to compare and rank similar yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue additional equity or incur debt, and the cost to us of any such issuance or incurrence.
Changes in the legal and regulatory environment governing the oil and natural gas industry, particularly changes in the current Oklahoma forced pooling system, could have a material adverse effect on our business.
Our business is subject to various forms of extensive government regulation, including laws and regulations concerning the location, spacing and permitting of the oil and natural gas wells the New Source Group drills and the disposal of saltwater produced from such wells, among other matters. In particular, our business relies heavily on a methodology available in
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Oklahoma known as “forced pooling,” which refers to the ability of a holder of an oil and natural gas interest in a particular prospective drilling spacing unit to apply to the Oklahoma Corporation Commission for an order forcing all other holders of oil and natural gas interests in such area into a common pool for purposes of developing that drilling spacing unit. Changes in the legal and regulatory environment governing our industry, particularly any changes to Oklahoma forced pooling procedures that make forced pooling more difficult to accomplish, could result in increased compliance costs and adversely affect our business and results of our operations.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated as a result of future legislation.
The Obama Administration’s budget proposal for fiscal year 2014 includes proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (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 U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could increase the taxable income allocable to our common unitholders and negatively impact the value of an investment in our common units.
We 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 are subject to a variety of stringent governmental laws and regulations relating to protection of the environment, worker health and safety and the use and storage of chemicals and gases used in our analytical and manufacturing processes and the discharge and disposal of wastes generated by those processes. 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 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 to incur costs or liabilities to mitigate or remediate pollution conditions caused by our operations or attributable to former owners or operators. If we fail to control the use, or adequately restrict the emission or discharge, of hazardous substances or wastes, we 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 to increase our capital expenditures or could result in increased operating expenses.
Due to concern over the risk of climate change, there has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. Regulatory frameworks adopted, or being considered for adoption, to reduce GHG emissions include cap and trade regimes, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates for renewable energy. For example, the European Emissions Trading Scheme is a program through which many of the European Union member states are implementing cap and trade controls covering numerous power stations and industrial facilities. Also, international accords for GHG reduction are evolving, but they have uncertain timing and outcome, making it difficult to predict their business impact. These proposed or promulgated laws and legal initiatives apply or could apply in countries where we have interests or may have interests in the future. These requirements could make our products and services more expensive, lengthen project implementation times, and reduce demand for the production of oil and natural gas, which could decrease demand for our products and services. In the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing emissions of GHGs and Congress has from time to time considered legislation to reduce emissions of GHGs but no such legislation has yet been adopted. However, the United States Environmental Protection Agency (“EPA”) has made findings in December 2009 that emissions of GHGs present a danger to public health and the environment and, based on these findings, has adopted regulations under existing provisions of the federal Clean Air Act that restrict emissions of GHGs from certain large stationary sources that are potential major sources of GHG emissions and that require the monitoring and reporting of GHG emissions from specified onshore and offshore production sources in the United States on an annual basis, which include the operations of many of our exploration and production clients. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions in the United State would impact our business, any such future laws and regulations that require
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reporting of GHGs or otherwise limit emissions of GHGs from our clients’ operations could require our clients to incur increased costs and also could adversely affect demand for the oil and natural gas that they produce, which could decrease demand for our products and services.
The New Source Group’s operations are subject to worker health and safety as well as environmental laws and regulations which may expose the New Source Group and us to significant costs and liabilities.
The New Source Group’s oil and natural gas exploration, production and processing operations on our behalf are subject to stringent federal, regional, state and local laws and regulations governing worker health and safety aspects of the operation, the discharge of materials into the environment and the protection of the environment. These laws and regulations may impose on those operations numerous requirements, including the obligation to obtain a permit before conducting drilling, underground injection or other regulated activities; restrictions on the types, quantities and concentration of materials that can be released into the environment; limitations or prohibitions of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; specific health and safety criteria to protect workers; and the responsibility for cleaning up any pollution resulting from operations. Numerous governmental authorities such as the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; the issuance of injunctions limiting or preventing some or all of the operations; and delays in granting permits and cancellation of leases.
There is an inherent risk of incurring significant environmental costs and liabilities in the performance of the New Source Group’s operations, some of which may be material, due to the New Source Group’s handling of petroleum hydrocarbons and wastes, emissions to air and water, the underground injection or other disposal of wastes and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the New Source Group and we may be 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 the New Source Group and us to significant costs or liabilities that could have a material adverse effect on our financial condition or the results of operations and our ability to make distributions to our unitholders. Aside from government agencies, the owners of properties where our wells are located, the operators of facilities where our petroleum hydrocarbons or wastes are taken for processing, reclamation or disposal and other private parties may be able to sue the New Source Group and us to enforce compliance with environmental laws and regulations, collect penalties for violations or obtain damages for any related personal injury or property damage. Some of our properties are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities or waste handling, emission, waste management or cleanup requirements could require the New Source Group and us to incur significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our competitive position or financial condition, the results of operations, or our ability to make distributions to our unitholders. We may not be able to recover some or any of these costs from insurance.
Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that the New Source Group produces for us, while the physical effects of climate change could disrupt the production and result in significant costs in preparing for or responding to those effects.
Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in producing oil and natural gas and the demand for and consumption of oil and natural gas (due to change in both costs and weather patterns). In December 2009, the EPA determined that atmospheric concentrations of GHGs present an endangerment to public health and welfare because such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Consistent with its findings, the EPA adopted regulations under the CAA that establish PSD and Title V permit reviews for GHG emissions from certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain oil and natural gas production facilities on an annual basis, which includes certain of the New Source Group operations on our behalf. The EPA’s GHG rules could adversely affect the New Source Group’s operations and restrict or delay the New Source Group’s ability to obtain air permits for new or modified facilities.
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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, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact the New Source Group’s operations and our business, any such future laws and regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the New Source Group’s equipment and operations could require it and us to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with those operations, and such requirements also could adversely affect demand for the oil and natural gas that the New Source Group produces on our behalf.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms and floods. If any such effects were to occur, they could have an adverse effect on the New Source Group’s exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and the results of operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. Our insurance may not cover some or any of the damages, losses, or costs that may result from potential physical effects of climate change.
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 and natural gas wells and adversely affect our production.
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 but the EPA has asserted federal regulatory authority under the SDWA over certain hydraulic fracturing involving the use of diesel fuel and issued final permitting guidance in February 2014 for hydraulic fracturing activities using diesel fuels. In November 2011, the EPA announced its intent to develop and issue regulations under the federal Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and it continues to project the issuance of an Advance Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations but it does not state a deadline for such issuance. 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 the New Source Group 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. In addition, 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 the New Source Group 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.
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. 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 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards for shale gas in 2014. Also, in May 2013, the BLM published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that, if adopted, would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water that returns to the surface. 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 under the SDWA or other regulatory mechanisms.
Risks Related to Our Indebtedness
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Our revolving credit facility contains substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions to our unitholders.
The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. Our ability to comply with these restrictions and covenants in our revolving credit facility in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of our revolving credit facility that are not cured or waived within the appropriate time periods provided in our revolving credit facility, all or a significant portion of our indebtedness may become immediately due and payable, our ability to make distributions to our unitholders will be inhibited and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our revolving credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our revolving credit facility, the lenders could seek to foreclose on our assets.
Our revolving credit facility is reserve-based, and thus we are permitted to borrow under our revolving credit facility in an amount up to the borrowing base, which is primarily based on the value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which takes into account the prevailing natural gas, NGL and oil prices at such time, as adjusted for the impact of our derivative contracts. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.
A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we will be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our revolving credit facility.
The variable rate indebtedness in our revolving credit facility subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.
Our borrowings under our revolving credit facility bear interest at rates that may vary, exposing us to interest rate risk. If such rates increase, our debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease.
Our level of indebtedness could affect our operations in several ways, including the following:
| • | a significant portion of our cash flows could be used to service our indebtedness; |
| • | a high level of debt would increase our vulnerability to general adverse economic and industry conditions; |
| • | the covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; |
| • | a high level of debt could place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; |
| • | our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry; |
| • | a high level of debt may make it more likely that a reduction in the borrowing base of our revolving credit facility following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings; and |
| • | a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general partnership or other purposes. |
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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 Our Common Units
Our general partner and its affiliates will have conflicts of interest with, and owe limited fiduciary duties to, us, which may permit them to favor their own interests to the detriment of our unitholders.
The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to the owners of our general partner. However, certain directors and officers of our general partner, including David J. Chernicky and Kristian B. Kos, are directors and/or officers of affiliates of our general partner (including members of the New Source Group), and will continue to have economic interests, investments and other economic incentives in the New Source Group. Conflicts of interest exist and may arise in the future between our general partner and its affiliates (including members of the New Source Group), on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders and us. These potential conflicts include, among others, the following situations:
| • | neither our partnership agreement nor any other agreement requires New Source Energy to pursue a business strategy that favors us. The directors and officers of New Source Energy have a fiduciary duty to make decisions in the best interests of its equity holders, which may be contrary to our interests; |
| • | our general partner is allowed to take into account the interests of parties other than us, such as its owners, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders; |
| • | New Source Energy is not limited in its ability to compete with us, including with respect to future acquisition opportunities, and is under no obligation to offer assets to us; |
| • | except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; |
| • | many of the officers and directors of our general partner who will provide services to us will devote time to affiliates of our general partner, including New Source Energy, and may be compensated for services rendered to such affiliates; |
| • | our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without such limitations, reductions, and restrictions, might constitute breaches of fiduciary duty. By purchasing common units, unitholders are consenting to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law; |
| • | while our general partner determines the amount and timing of our drilling program under our development agreement, our contract operator, New Dominion, may propose changes to such program as a result of operating or other conditions; |
| • | our general partner determines the amount and timing of our asset purchases and sales, borrowings, issuance of additional partnership interests, other investments, including investment capital expenditures in other partnerships with which our general partner is or may become affiliated, and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to unitholders; |
| • | our general partner determines whether a cash expenditure is classified as a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus in any given period and the ability of the subordinated units to convert into common units; |
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| • | our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; |
| • | our partnership agreement permits us to classify up to $11.5 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights; |
| • | our general partner decides whether to retain separate counsel, accountants, or others to perform services for us; |
| • | our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations; |
| • | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; |
| • | our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us; |
| • | our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and |
| • | our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including New Source Energy. |
New Source Energy and other affiliates of our general partner are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses.
Our partnership agreement provides that the New Source Group is not restricted from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, the New Source Group may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.
The members of the New Source Group are established participants in the oil and natural gas industry, and each may have resources greater than ours, which factors may make it more difficult for us to compete with them with respect to commercial activities as well as for potential acquisitions. As a result, competition from these affiliates could adversely impact our results of operations and cash available for distribution to our unitholders.
Neither we nor our general partner had any employees and we relied primarily on the employees of New Source Energy and New Dominion to manage our business. The management team of New Source Energy, which includes the individuals who manage us, also performed substantially similar services for its assets and operations, and thus is not solely focused on our business.
Neither we nor our general partner had any employees and we relied primarily on New Source Energy and New Dominion to operate our assets. We and our general partner had entered into various agreements with the New Source Group, pursuant to which, among other things, the New Source Group had agreed to operate our assets, perform our drilling operations and provide other management and administrative services for us and our general partner.
The New Source Group provides substantially similar services with respect to its own assets and operations. Because the New Source Group provides services to us that are substantially similar to those performed for its members, the New Source Group may not have sufficient human, technical and other resources to provide those services at a level that the New Source Group would be able to provide to us if it were solely focused on our business and operations. The New Source Group may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to the interests of our affiliates. There is no requirement that the New Source Group favor us over itself in providing its services. If the employees of the New Source Group do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
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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 years ended December 31, 2012 and 2011, management considered the failure to identify errors in a timely manner to be material weaknesses in New Source Energy’s internal control over financial reporting under the standards established by the United States Public Company Accounting Oversight Board, or the “PCAOB Standards.” Under the PCAOB standards, a material weakness is defined as a deficiency, or a combination of deficiencies, in internal control, such that there is a reasonable possibility that a material misstatement of the entity’s financial statements will not be prevented, or detected and corrected on a timely basis. In response to these material weaknesses, New Source Energy evaluated its historical financial and operations data for further deficiencies and has changed the method by which it computes its natural gas and NGL sales volumes to ensure that such volumes match the actual volumes processed by its first purchasers. New Source Energy also instituted additional control procedures around the research and recording of non-recurring transactions.
In connection with the audit of our consolidated financial statements for the year ended December 31, 2013, we and our independent registered public accounting firm identified a material weakness in our internal controls over financial reporting. This material weakness related to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review 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 United States generally accepted accounting principles. In the current period these non-routine transactions impacted the recording of equity based compensation, cash-flow presentations, required business combination adjustments 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 following reviews of our accounting and finance function conducted by members of senior management and by a third-party consultant, there can be no assurance that we will remediate this material weakness or avoid future weaknesses or deficiencies. Any failure to remediate this material weakness 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. If our management was to conclude in its reports that our internal control over financial reporting was not effective, investors could lose 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, FINRA or other regulatory authorities, as well as increasing the risk of liability arising from litigation based on securities law.
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.
Cost reimbursements due to New Source Energy for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders.
We and our general partner were parties to an omnibus agreement with New Source Energy through December 31, 2013, pursuant to which, among other things, we made payments to New Source Energy for management and administrative services provided on our behalf. Through December 31, 2013, we paid New Source Energy a quarterly fee of $675,000 for the provision of such services. After December 31, 2013, our general partner provides us with management and administrative services that we believe are necessary to allow us to operate, manage and grow our business. All actual direct and indirect expenses our general partner incurs will be reimbursed by us in an amount equal to the cost of such actual and indirect expenses, without a
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cap on the amount of such reimbursement. For the year ended December 31, 2013, the actual cost of the services provided to us by New Source Energy was $6.1 million.
There is no assurance that management and administrative expenses will not increase substantially from the omnibus fees incurred in previous periods. Additionally, we are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit. These payments will be substantial and will reduce the amount of cash available for distribution to unitholders.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
Our general partner has the right (but not the obligation), at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (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.
Our unitholders who fail to furnish certain information requested by our general partner or who our general partner determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.
We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any limited partner. Our general partner may require any limited partner or transferee to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units and subordinated units of any holder that is not an eligible citizen or fails to furnish the requested information.
Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.
If our general partner determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our general partner may adopt such amendments to our partnership agreement as it determines are necessary or advisable to obtain proof of the U.S. federal income tax status of our limited partners (and their owners, to the
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extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on our ability to operate our assets or generate revenues from our assets or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status.
Our unitholders have limited voting rights and are not entitled to elect our general partner or its board of directors. The owners of our general partner have the power to appoint and remove our general partner’s directors.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is appointed by its owners, which are New Source Energy and certain of its affiliates. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our general partner has control over all decisions related to our operations. Given the ownership interests of our general partner and its affiliates, 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 (including common units held by New Source Energy) after the subordination period has ended. Assuming we do not issue any additional common units and New Source Energy does not transfer its common units, New Source Energy and certain of its affiliates will have the ability to amend our partnership agreement, including our policy to distribute all of our available cash to our unitholders, without the approval of any other unitholder once the subordination period ends. Furthermore, the goals and objectives of New Source Energy and such affiliates relating to us may not be consistent with those of a majority of the other unitholders.
Our general partner is required to deduct estimated maintenance capital expenditures from our operating surplus, which may result in less cash available for distribution to unitholders from operating surplus than if actual maintenance capital expenditures were deducted.
Maintenance capital expenditures are those capital expenditures required to maintain our long-term asset base, including expenditures to replace our oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property. Our partnership agreement requires our general partner to deduct estimated, rather than actual, maintenance capital expenditures from operating surplus in determining cash available for distribution from operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by our general partner’s board of directors at least once a year, provided that any change is approved by the conflicts committee of our general partner’s board of directors. Following the completion of the MCE acquisition, management and the board of directors of our general partner determined to prepare the estimate of maintenance capital expenditures based on the expected capital expenditures to replace our revenue generating assets (including production and producing reserves from our oil and gas operations and vehicles and other equipment from our oilfield services operations) based on expectations of the replacement costs for such assets during the fiscal year on an individualized basis. 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 |
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has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote any units it may own, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation involving us or to any amendment to the partnership agreement;
| • | provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long it acted in good faith, meaning it believed that the decisions were not adverse to the interests of our partnership; |
| • | provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners with respect to any transaction involving an affiliate if: |
| • | the transaction with an affiliate or the resolution of a conflict of interest is: |
| • | approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or |
| • | approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates; or |
| • | the board of directors of our general partner acted in good faith in taking any action or failing to act; |
| • | provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and |
| • | provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner’s board of directors or the conflicts committee of our general partner’s board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. |
Even if our unitholders are dissatisfied, they cannot remove our general partner without consent of the owners of our general partner.
The public unitholders are unable to remove our general partner without Deylau and certain of its affiliates consent because Deylau and certain of its affiliates own sufficient units to be able to prevent our general partner’s removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. Kristian B. Kos, our Chief Executive Officer and President and a member of the board of directors of our general partner, is the sole member of Deylau. As of December 31, 2013, Deylau owned approximately 6.9% of our outstanding common units and a 69.4% membership interest in our general partner. Additionally, David J. Chernicky and entities he controls, including New Source Energy, collectively held (i) 30.6% of our general partner (ii) 28% of our then outstanding 9,599,578 common units and (iii) 100% of our 2,205,000 subordinated units.
Control of our general partner and its incentive distribution rights may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner, who are New Source Energy and certain of its affiliates, from transferring all or a portion of their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and thereby influence the decisions made by the board of directors and officers in a manner that may not be aligned with the interests of our unitholders.
In addition, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights.
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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 MCE, LP 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 our MCE Acquisition, which include the President and Chief Executive Officer of our general partner and a director of our general partner, retained Class B Units in MCE, LP in connection with the MCE acquisition. The MCE, LP partnership agreement provides that the Class B Units have the right to receive an increasing percentage of quarterly distributions by MCE, LP of its available cash above specified thresholds. As a result, the cash distributions to which the holders of MCE, LP 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 MCE, LP 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 MCE, LP Class B Units, please see “Note 12-Unitholders’ Equity” in Part II, Item 8 “Financial Statements and Supplementary Data.”
We may issue an unlimited number of additional units, including units that are senior to the common units, without unitholder approval, which would dilute unitholders’ ownership interests.
Our partnership agreement does not limit the number of additional common units that we may issue at any time without the approval of our unitholders. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
| • | our unitholders’ proportionate ownership interest in us will decrease; |
| • | the amount of cash available for distribution on each unit may decrease; |
| • | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
| • | the ratio of taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit may be diminished; and |
| • | the market price of our common units may decline. |
Our partnership agreement restricts the limited voting rights of unitholders, other than our general partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.
Our partnership agreement restricts unitholders’ limited voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding (other than our general partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of directors of our general partner) cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.
Our general partner has a call right that may require common unitholders to sell their common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than the then-current market price of the common units. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any
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return on their investment. Our unitholders also may incur a tax liability upon a sale of their common units. As of December 31, 2013, our general partner and its affiliates owned 36.9% of our 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 and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated maintenance capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus is defined in our partnership agreement and generally would result from cash received from non-operating sources such as sales of properties and issuances of debt and equity interests. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98.0% to our unitholders and 2.0% to our general partner, and will result in a decrease in our minimum quarterly distribution.
Our partnership agreement allows us to add to operating surplus $11.5 million. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.
Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, we currently conduct business in Oklahoma and may in the future conduct business in other states. A unitholder could be liable for our obligations as if it 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.
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; |
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| • | fluctuations in broader securities market prices and volumes, particularly among securities of oil and natural gas companies and securities of publicly traded limited partnerships and limited liability companies; |
| • | changes in market valuations of similar companies; |
| • | departures of key personnel; |
| • | commencement of or involvement in litigation; |
| • | variations in our quarterly results of operations or those of other oil and natural gas companies; |
| • | variations in the amount of our quarterly cash distributions to our unitholders; |
| • | future issuances and sales of our common units; and |
| • | changes in general conditions in the U.S. economy, financial markets or the oil and natural gas industry. |
In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.
We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our revolving credit facility may restrict our ability to make distributions.
Our partnership agreement allows us to borrow to make distributions. We may make short-term borrowings under our revolving credit facility to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short-term fluctuation in our working capital that would otherwise cause volatility in our quarter-to-quarter distributions.
The terms of our revolving credit facility restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.
Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we may be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:
| • | general economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds; |
| • | conditions in the oil and natural gas industry; |
| • | the market price of, and demand for, our common units; |
| • | our results of operations and financial condition; and |
| • | prices for oil, NGLs and natural gas. |
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE under the symbol “NSLP.” Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of NYSE corporate governance requirements. See “Item 10 - Directors, Executive Officers and Corporate Governance - Management of New Source Energy Partners L.P.”
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Tax Risks to Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.
At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such tax on us by any such state will reduce the cash available for distribution to our unitholders.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly-traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.
You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, you will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability resulting from that income.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.
We will be considered to have constructively terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our
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termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine in a timely manner that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 to its unitholders for the tax year in which the termination occurs.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income result in a decrease in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investments in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their shares of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.
The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest by the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest by the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
We will treat each purchaser of our common units as having the same tax benefits without regard to the 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
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based upon the date the underlying property is placed in service. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered 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 U.S. federal income taxes, you will likely be subject to return filing requirements and other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. 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 U.S. federal, foreign, state and local tax returns.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
| ITEM 2. | PROPERTIES |
Our Properties
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Our oil and natural gas properties are located in the Greater Golden Lane, Luther and Southern Dome fields primarily within the Hunton Formation of east-central Oklahoma and consist of mature, legacy oil and natural gas reservoirs. Our oil and natural gas properties consist of non-operated working interests in producing and undeveloped leasehold acreage, our properties include 302 gross (139.7 net) producing wells with working interests ranging from 7.5% to 100% (46.3% weighted average); and 161 gross (40.1 net) proved undeveloped drilling locations with working interests ranging from 1% to 96.4% (24.9% weighted average).
As of December 31, 2013, two rigs are being used to drill on our oil and natural gas properties, and the number of rigs may be increased to up to four rigs over the next twelve months. Since our initial public offering, we have completed 28 gross (10.6 net) wells.
The following table summarizes information related to our estimated oil and natural gas reserves as of December 31, 2013 and the average net production for the year ended December 31, 2013 from our oil and gas properties.
| Estimated Proved Reserves as of December 31, 2013(1) | Production for the Year Ended December 31, 2013 (4) | Number of Wells/Drilling Locations as of December 31, 2013 | |||||||||||||||||||||||||
| Proved Reserves | Total Proved (MBoe) | Percent of Total | Percent Oil | Percent NGLs | Percent Natural Gas | Percentage of Depletion (2) | PV-10 (MM) (3) | Average Net Daily Production (Boepd) | Average Working Interest | Gross | Net | ||||||||||||||||
| Producing | 11,930.8 | 57.8 | 7.7 | 66.5 | 25.8 | 82.4 | 158.3 | 3,658 | 46.3 | % | 302 | 139.7 | |||||||||||||||
| Non-Producing | 552.8 | 2.7 | 1.5 | 64.1 | 34.4 | — | 7.6 | — | 32.3 | % | 6 | 1.9 | |||||||||||||||
| Undeveloped | 8,155.0 | 39.5 | 6.3 | 59.7 | 34.0 | — | 46.8 | — | 24.9 | % | 161 | 40.1 | |||||||||||||||
| Total | 20,638.6 | 100.0 | 7.0 | 63.8 | 29.2 | 47.6 | 212.7 | 3,658 | 38.7 | % | 469 | 181.7 | |||||||||||||||
| (1) | Proved reserves were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months, which were $96.78 per Bbl of crude oil, $36.78 per Bbl of NGLs and $3.67 per Mcf of natural gas. Adjustments were made for location and the grade of the underlying resource, which resulted in an average decrease of $3.07 per Bbl of crude oil, an average decrease of $1.17 per Bbl of NGLs and an average decrease of $0.12 per Mcf of natural gas. |
| (2) | Percentage of depletion was calculated by dividing cumulative production from our properties in these fields by the sum of proved reserves attributable to such properties and cumulative production from such properties. |
| (3) | PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month price for each of the preceding twelve months. PV-10 typically differs from the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) because it does not include the effects of income tax. We 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 natural gas and crude oil properties. PV-10 is used by the industry and by our management as an arbitrary reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities that are not dependent on the taxpaying status of the entity. |
| (4) | Includes production for the March Acquired Properties, the May Acquired Properties, the July Scintilla Acquired Properties and Southern Dome Acquired Properties from the effective date of the respective acquisition. |
We use the term “conventional resource play” to refer to high water saturation (35-99%) hydrocarbon reservoirs that typically have been deemed not prospective by others. Conventional resource plays are usually located around and below conventional reservoirs, although they can exist independently. These reservoirs tend to be continuous hydrocarbon zones existing over a contiguous and potentially large geographical area. Conventional resource plays exhibit low exploration risk with consistent results, and with the implementation of specialized processes, we believe we have the ability to economically develop these large-scale reservoirs.
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We have access to the development and operational experience of the New Source Group in support of our operating activities. The senior geologist and other professional staff of members of the New Source Group have developed conventional resource plays for 25 years, which have provided them with insights on the physical processes at work and a significant amount of practical operating experience in how to economically produce from these reservoirs. As a result of this experience, the New Source Group has developed and refined processes that it will utilize in developing our conventional resource plays. Prior conventional resource plays in which the senior geologist for New Source Energy has used these specialized processes to successfully and economically produce oil and natural gas include the Red Fork formation in the Mount Vernon field in central Oklahoma, which was developed in the late 1980s, and the Hunton Formation in the Carney and Golden Lane fields in central Oklahoma, which the New Source Group commenced developing in 1999. Each of these projects had been passed over by other industry operators because of its high saltwater content. The cumulative production from these fields from January 1, 1989 through December 31, 2013 following application of their specialized processes is 40.3 MMBoe.
Our Oilfield Services Operations
Our oilfield services segment operates an oilfield services business headquartered in Oklahoma City, Oklahoma and offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region, along with the provision of certain ancillary equipment necessary to perform such services, which may include spacer spools, double-stud adapters, blowout preventers, ram blocks, choke manifolds, accumulators and other various pressure components. In addition to our presence in the Mid-Continent region, we recently leased field offices in South Texas to focus on the Eagle Ford Shale and in West Texas to focus on the Permian Basin.
Oil and Natural Gas Data and Operations
Internal Controls over Reserves Estimation Process
Our management team works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Carol T. Bryant, our senior engineer, is the technical person within our company primarily responsible both for overseeing the preparation of our reserves estimates and for overseeing the reserves audit conducted by our third party petroleum engineer. Ms. Bryant has over 30 years of industry experience and has evaluated numerous properties throughout the United States with an emphasis on light oil and NGLs, heavy oil, conventional and unconventional reservoirs, operations, reservoir development and property evaluation. Ms. Bryant holds a Petroleum Engineering degree from the University of Tulsa, which she received in 1980. For further information regarding Ms. Bryant’s qualifications, see “Item 10 - Directors, Executive Officers and Corporate Governance Management.”
Our management team plans to meet with representatives of our independent reserve engineers periodically throughout the year to review properties and discuss methods and assumptions used in preparation of the proved reserves estimates. Historically, we have had no formal committee specifically designated to review our reserves reporting and our reserves estimation process, and our reserve report was reviewed by our senior geologist and senior engineer with representatives of our independent reserve engineers and internal technical staff.
Technology Used to Establish Proved Reserves
As referred to in this Annual Report on Form 10-K, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
To establish reasonable certainty with respect to our estimated proved reserves, our independent reserve engineering firm employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, 3-D seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped
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locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques. In addition to assessing reservoir continuity, geologic data from well logs, core analyses and 3-D seismic data were used to estimate original oil and natural gas in place in certain areas.
Independent Reserve Engineers
The proved reserves estimates as of December 31, 2013 included in this Annual Report on Form 10-K have been independently prepared by Ralph E. Davis Associates, Inc., which was founded in 1924 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1529. Within Ralph E. Davis Associates, Inc., the technical person primarily responsible for preparing the estimates shown herein was its president, Allen C. Barron. Mr. Barron has been practicing consulting petroleum engineering at Ralph E. Davis Associates, Inc. since 1993. Mr. Barron is a Registered Professional Engineer in the State of Texas (License No. 49284) and has over 40 years of practical experience in petroleum engineering, with over 30 years’ experience in the estimation and evaluation of reserves. He graduated from the University of Houston in 1968 with a Bachelors of Science in Chemical and Petroleum Engineering. Mr. Barron meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Proved Undeveloped Reserves
As of December 31, 2013, our proved undeveloped reserves were 8.2 MMBoe. 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 based on the development agreement we are a party to with the New Source Group. Pursuant to the development agreement, our general partner will determine and periodically update our annual maintenance drilling budget, and will have the right to propose which wells are drilled based on our annual maintenance drilling budget.
Our eventual net leasehold position and working interests in our proved undeveloped properties will be determined through pooling and spacing procedures. For a discussion regarding additional working interests we may obtain through forced pooling, see “Specialized Processes - Forced Pooling Process.”
The following table presents changes applicable to the proved undeveloped reserves on our properties during the year ended December 31, 2013 (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 | ||
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.
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Production, Revenues and Price History
The following table summarizes information related to our production of our oil and natural gas products as of December 31, 2013, 2012 and 2011.
| Years Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Oil: | |||||||||||
| Production (Bbls) | 84,273 | 61,010 | 48,770 | ||||||||
| Average sales price (per Bbl), excluding derivatives | $ | 95.14 | $ | 91.30 | $ | 92.04 | |||||
| Natural Gas: | |||||||||||
| Production (Mcf) | 2,764,336 | 2,278,342 | 2,378,232 | ||||||||
| Average sales price (per Mcf), excluding derivatives | $ | 3.61 | $ | 2.65 | $ | 3.66 | |||||
| Natural Gas Liquids: | |||||||||||
| Production (Bbl) | 790,234 | 711,195 | 720,615 | ||||||||
| Average sales price (per Bbl), excluding derivatives | $ | 36.50 | $ | 33.74 | $ | 45.87 | |||||
| Oil Equivalents: | |||||||||||
| Production (Boe)(1) | 1,335,230 | 1,151,929 | 1,165,757 | ||||||||
| Average equivalent price (per Boepd) | $ | 35.15 | $ | 30.90 | $ | 39.68 | |||||
| Average daily production (Boepd) | 3,658 | 3,147 | 3,194 | ||||||||
| Average production costs (per Boepd)(2) | $ | 9.46 | $ | 5.40 | $ | 6.67 | |||||
| Average production taxes (per Boepd) | $ | 2.00 | $ | 0.99 | $ | 1.85 | |||||
| (1) | Determined using the ratio of 6 Mcf gas to 1 Bbl of crude oil. |
| (2) | Includes lease operating expense and workover expense. |
For a description of our historical revenues and unit costs, see “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations.”
Drilling Activity
The following table describes the development wells drilled on our acreage by us during the years ended December 31, 2013, 2012 and 2011.
| Productive Wells | Dry Wells | Total | |||||||||
| Year | Gross | Net | Gross | Net | Gross | Net | |||||
| 2013 | 28 | 10.6 | — | — | 28 | 10.6 | |||||
| 2012 | 12 | 3.8 | — | — | 12 | 3.8 | |||||
| 2011 | 22 | 8.3 | — | — | 22 | 8.3 | |||||
We drilled no exploratory wells on our acreage during these three years.
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Present Activities
The following table sets forth information about our wells for which drilling was in-progress or are pending completion at December 31, 2013, which are not included in the above table.
| Drilling In-Progress | Pending Completion | ||||||
| Gross | Net | Gross | Net | ||||
| Development wells | 5 | 1.6 | 3 | 1.0 | |||
| Exploratory wells | — | — | — | — | |||
| Total | 5 | 1.6 | 3 | 1.0 | |||
Productive Wells
The following table sets forth the number of oil and natural gas wells in which we owned a working interest as of December 31, 2013.
| Crude Oil | Natural Gas | Total | |||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||
| Greater Golden Lane | 26 | 14.1 | 234 | 99.6 | 260 | 113.7 | |||||
| Luther | 4 | 3.9 | 13 | 12.1 | 17 | 16.0 | |||||
| Southern Dome | 20 | 8.3 | 5 | 1.7 | 25 | 10.0 | |||||
| Total | 50 | 26.3 | 252 | 113.4 | 302 | 139.7 | |||||
The following table sets forth the number of producing horizontal and vertical completions in which we own a working interest as of December 31, 2013.
| Horizontal | Vertical | Total | |||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||
| Greater Golden Lane | 216 | 83.8 | 44 | 29.9 | 260 | 113.7 | |||||
| Luther | 10 | 9.1 | 7 | 6.9 | 17 | 16.0 | |||||
| Southern Dome | 16 | 6.3 | 9 | 3.7 | 25 | 10.0 | |||||
| Total | 242 | 99.2 | 60 | 40.5 | 302 | 139.7 | |||||
Acreage
The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2013.
| Undeveloped | Developed | Total | |||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||
| Greater Golden Lane | 9,079 | 3,230.0 | 102,880 | 40,345.4 | 111,959 | 43,575.4 | |||||||||||
| Luther | — | — | 10,560 | 10,094.3 | 10,560 | 10,094.3 | |||||||||||
| Southern Dome | — | — | 2,240 | 1,319.0 | 2,240 | 1,319.0 | |||||||||||
| Total | 9,079 | 3,230.0 | 115,680 | 51,758.7 | 124,759 | 54,988.7 | |||||||||||
The majority of our undeveloped acreage is subject to material near-term lease expiration risk. As of December 31, 2013, we held approximately 3,230 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, 2016, of which 433 net acres are scheduled to expire between January 1, 2014 and December 31, 2014, 710 net acres are scheduled to expire between January 1, 2015 and December 31, 2015, and 2,087 net acres are scheduled to expire between January 1, 2016 and December 31, 2016. Of our total estimated
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proved undeveloped reserves as of December 31, 2013 of 8,155 MBoe, 728 MBoe, or approximately 8.9%, is attributable to 40 gross (3.4 net) drilling locations within undeveloped acreage covered by leases set to expire before the associated wells are scheduled to be drilled. We intend, as ordinary course of business, to renew the aforementioned leases prior to expiration to avoid a reduction of our undeveloped acreage position. In addition, the impact of lease expirations may be mitigated through an acceleration of our drilling schedule, which is at the discretion of our contract operator. 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.”
Delivery Commitments
We have no delivery commitments with respect to our production.
Title to Properties
Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business. We believe that we directly or beneficially have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, neither we nor the New Source Group conduct material investigations of title at the time we acquire undeveloped properties. We and the New Source Group make title investigations and receive title opinions of local counsel, if at all, only before commencing drilling operations. We believe that we have satisfactory title to all of our other assets.
| ITEM 3. | LEGAL PROCEEDINGS |
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From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.
New Dominion, our contract operator and an affiliate of New Source Energy, has been named as a defendant in Mattingly v. Equal Energy, which was originally filed in Creek County District Court on August 16, 2010, was subsequently removed to the United States District Court for the Northern District of Oklahoma on September 8, 2010, but was remanded to state court on August 1, 2011. The plaintiffs have asserted claims individually and on behalf of a class of royalty owners alleging that the defendants, including New Dominion, breached certain duties owed to the plaintiffs arising from oil and gas leases between the plaintiffs and the defendants by allegedly deducting post-production costs in calculating the royalties paid to the plaintiffs under those leases and failing to credit the plaintiffs for all revenues, including those attributable to the sale of natural gas, NGLs, condensate and drip. The plaintiffs seek damages in excess of $10,000, punitive damages, interest, costs and attorneys’ fees.
Although we have not been made a party to this litigation, it is possible that we may be joined to the litigation as a defendant due to our acquisition of the IPO Properties in connection with our IPO and subsequent acquisitions of property from New Source Energy and the future calculation of royalties paid to the plaintiffs in the litigation.
We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.
| ITEM 4. | MINE SAFETY DISCLOSURES |
Not applicable.
PART II.
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| 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. As of April 3, 2014, the closing price for the common units was $23.41 per unit and there were approximately 10 unitholders of record. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record.
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 | Cash Distributions per Common Unit (1) (2) | ||||
| High | Low | ||||
| 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 (3) | $20.55 | $19.19 | $0.274 | ||
(1) Represents cash distributions attributable to the quarter and declared and paid to limited partner unitholders within 60 days after quarter end.
(2) We also paid cash distributions to our general partner with respect to its general partner interest and with respect to the IDR's described below, no distributions were made.
(3) 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 New Source Energy.
Cash Distributions to Unitholders
We make cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Additionally, under our revolving credit facility, we will not be able to pay distributions to unitholders in any such quarter in the event there exists a borrowing base deficiency or an event of default either before or after giving effect to such distribution or we are not in pro forma compliance with our revolving credit facility after giving effect to such distribution.
Our Cash Distribution Policy
Our partnership agreement requires that, within 45 days after the end of each quarter, 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; |
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| • | comply with applicable law, any of our debt instruments or other agreements; or |
| • | provide funds for distributions to our unitholders (including our general partner) for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for the payment of future distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for such quarter); |
| • | plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter. |
During Subordination Period
Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner during the subordination period:
| • | first, 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.
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.
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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 |
| • | 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 “Item 12 - Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding our equity compensation plans as of December 31, 2013.
Unregistered Sales of Equity Securities
None not previously reported on a current report on Form 8-K.
Issuer Purchases of Equity Securities
None.
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| ITEM 6. | SELECTED FINANCIAL DATA |
We were formed in October 2012 and do not have historical financial operating results for periods prior to our formation. The contribution of the IPO Properties to us by New Source Energy in connection with our IPO in February 2013 was a transaction between businesses under common control. Accordingly, we have reflected the IPO Properties in our financial statements retroactively at carryover basis. Due to the factors described in “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Operating Expenses - General and administrative,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations - Operating Expenses - Depreciation, depletion and amortization” , “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Income Taxes,” and “Item 8 - Financial Statements and Supplementary Data,” all contained herein, our results of operations for the year ended December 31, 2013 are not comparable to the historical results attributable to the IPO Properties as a result of a change in entity classification under the Internal Revenue Code. The following table shows summary historical financial data attributable to the IPO Properties during the years ended December 31, 2012, 2011 and 2010, which comprised the entirety of our operating assets, during those periods.
The selected historical financial data as of and for the years ended December 31, 2013, 2012, 2011 and 2010 are derived from the audited historical financial statements.
The following table also presents Adjusted EBITDA, which we use in evaluating the liquidity of our business. This financial measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. We explain this measure below and reconcile it to net income and net cash from operating activities, its most directly comparable financial measures calculated and presented in accordance with GAAP.
| Year Ended December 31, | |||||||||||||||
| 2013 | 2012 | 2011 | 2010 | ||||||||||||
| REVENUES: | (in thousands) | ||||||||||||||
| Oil sales | $ | 8,090 | $ | 5,570 | $ | 4,489 | $ | 5,136 | |||||||
| Natural gas sales | 10,000 | 6,030 | 8,713 | 9,409 | |||||||||||
| Natural gas liquids sales | 28,847 | 23,996 | 33,058 | 25,909 | |||||||||||
| Service and rentals | 3,738 | — | — | — | |||||||||||
| Total revenues | 50,675 | 35,596 | 46,260 | 40,454 | |||||||||||
| OPERATING COSTS AND EXPENSES: | |||||||||||||||
| Oil and natural gas production expenses | 12,631 | 6,217 | 7,875 | 7,639 | |||||||||||
| Oil and natural gas production taxes | 2,669 | 1,144 | 2,155 | 2,876 | |||||||||||
| Cost of providing service and rentals | 2,040 | — | — | — | |||||||||||
| General and administrative | 14,760 | 12,660 | 6,928 | 649 | |||||||||||
| Depreciation, depletion, and amortization | 18,556 | 14,409 | 14,738 | 14,909 | |||||||||||
| Accretion expense | 209 | 116 | 55 | 50 | |||||||||||
| Total operating costs and expenses | 50,865 | 34,546 | 31,751 | 5,136 | |||||||||||
| Operating (loss) income | (190 | ) | 1,050 | 14,509 | 14,331 | ||||||||||
| OTHER INCOME (EXPENSE): | |||||||||||||||
| Interest expense | (4,078 | ) | (3,202 | ) | (3,735 | ) | (2,648 | ) | |||||||
| Net gain (loss) on commodity derivatives | (5,548 | ) | 7,057 | (1,349 | ) | (516 | ) | ||||||||
| Gain on investment in acquired business | 22,709 | — | — | — | |||||||||||
| Other income | 1,603 | — | — | — | |||||||||||
| Income before income taxes | 14,496 | 4,905 | 9,425 | 11,167 | |||||||||||
| Income tax benefit (expense) | 12,126 | (1,796 | ) | (10,502 | ) | — | |||||||||
| Net income (loss) | $ | 26,622 | $ | 3,109 | $ | (1,077 | ) | $ | 11,167 | ||||||
| Net income per common unit for the period from February 13, 2013 to December 31, 2013 | $ | 2.42 | |||||||||||||
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| Year Ended December 31, | |||||||||||||||
| 2013 | 2012 | 2011 | 2010 | ||||||||||||
| (in thousands) | |||||||||||||||
| Balance Sheet Data: | |||||||||||||||
| Accounts receivable | $ | 12,609 | $ | 5,663 | $ | 6,544 | $ | 6,122 | |||||||
| Other current assets | 8,405 | 25 | 1,134 | 938 | |||||||||||
| Total property and equipment, net | 171,034 | 91,423 | 94,468 | 86,049 | |||||||||||
| Other assets | 62,662 | 2,823 | 2,674 | 1,430 | |||||||||||
| Total assets | $ | 254,710 | $ | 99,934 | $ | 104,820 | $ | 94,539 | |||||||
| Current liabilities | $ | 17,281 | $ | 1,973 | $ | 4,076 | $ | 4,909 | |||||||
| Long-term debt | 80,014 | 68,000 | 68,500 | 60,000 | |||||||||||
| Other long-term liabilities | 10,162 | 13,986 | 13,824 | 2,056 | |||||||||||
| Partners' capital / Total parent net investment | 147,253 | 15,975 | 18,420 | 27,574 | |||||||||||
| Total liabilities and parent net investment | $ | 254,710 | $ | 99,934 | $ | 104,820 | $ | 94,539 | |||||||
| Year Ended December 31, | |||||||||||||||
| 2013 | 2012 | 2011 | 2010 | ||||||||||||
| (in thousands) | |||||||||||||||
| Other Financial Data: | |||||||||||||||
| Adjusted EBITDA | $ | 26,927 | $ | 29,766 | $ | 32,273 | $ | 30,123 | |||||||
| Cash Flow Data: | |||||||||||||||
| Net cash provided by operating activities | $ | 18,364 | $ | 27,799 | $ | 30,133 | $ | 27,940 | |||||||
| Net cash used in investing activities | $ | (51,023 | ) | $ | (12,162 | ) | $ | (23,818 | ) | $ | (19,226 | ) | |||
| Net cash provided by (used in) financing activities | $ | 39,950 | $ | (15,637 | ) | $ | (6,315 | ) | $ | (8,714 | ) | ||||
Non-GAAP Financial Measure
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, and is not a measure of net income or cash flows as determined by United States generally accepted accounting principles, or GAAP.
We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, non-cash compensation expense, acquisition related general and administrative expense, unrealized derivative gains and losses and other non-recurring gains and losses, such as our gain on investment in a subsidiary under common control and deferred financing costs.
Our management believes Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.
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The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.
| Year Ended December 31, | |||||||||||||||
| 2013 | 2012 | 2011 | 2010 | ||||||||||||
| (in thousands) | |||||||||||||||
| Adjusted EBITDA Reconciliation to Net Income (Loss): | |||||||||||||||
| Net income (loss) | $ | 26,622 | $ | 3,109 | $ | (1,077 | ) | $ | 11,167 | ||||||
| Unrealized (gain) loss on derivatives | 3,619 | (1,070 | ) | (150 | ) | 1,349 | |||||||||
| Change in fair value of contingent consideration | (1,600 | ) | — | — | — | ||||||||||
| Gain on investment in subsidiary under common control | (22,709 | ) | — | — | — | ||||||||||
| Non-cash compensation expense | 7,839 | 8,204 | 4,470 | — | |||||||||||
| Acquisition related general and administrative expense | 2,078 | — | — | — | |||||||||||
| Accretion expense | 209 | 116 | 55 | 50 | |||||||||||
| Interest expense | 4,078 | 3,202 | 3,735 | 2,648 | |||||||||||
| Abandoned offering costs | 361 | — | — | — | |||||||||||
| Depreciation, depletion and amortization | 18,556 | 14,409 | 14,738 | 14,909 | |||||||||||
| Income tax expense (benefit) | (12,126 | ) | 1,796 | 10,502 | — | ||||||||||
| Adjusted EBITDA | $ | 26,927 | $ | 29,766 | $ | 32,273 | $ | 30,123 | |||||||
| Adjusted EBITDA Reconciliation to Net Cash Provided By Operating Activities: | |||||||||||||||
| Net cash provided by operating activities | $ | 18,364 | $ | 27,799 | $ | 30,133 | $ | 27,940 | |||||||
| Cash interest expense | 2,061 | 2,553 | 2,250 | 2,262 | |||||||||||
| Abandoned offering costs | 361 | — | — | — | |||||||||||
| Acquisition related general and administrative expense | 2,078 | — | — | — | |||||||||||
| Current income tax liability assumed by parent | — | 172 | — | — | |||||||||||
| Payments for derivative option premiums | 1,334 | — | — | — | |||||||||||
| Changes in operating assets and liabilities | 2,729 | (758 | ) | (110 | ) | (79 | ) | ||||||||
| Adjusted EBITDA | $ | 26,927 | $ | 29,766 | $ | 32,273 | $ | 30,123 | |||||||
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
This Management’s Discussion and Analysis of Financial Condition and Results of Operations contains a discussion of our business, including a general overview of our properties, our results of operations, our liquidity and capital resources, and our quantitative and qualitative disclosures about market risk.
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the “Item 8 - Financial Statements and Supplementary Data.” The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control, including among other things, the risk factors discussed in “Item 1A - Risk Factors” of this Annual Report on Form 10-K. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors
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discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statements Regarding Forward-Looking Statements” in the front of this Annual Report on Form 10-K.
Overview
We are a Delaware limited partnership formed in October 2012 by New Source Energy to own and acquire oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. We currently operate in two reportable segments: exploration and production segment and oilfield services segment. For additional information about our segments, see “Note 15 - Segment Information” in “Item 8 - Financial Statements and Supplementary Data.” Our oil and natural gas properties consist of non-operated working interests in the Misener-Hunton formation (the “Hunton Formation”), a conventional resource reservoir located in east-central Oklahoma. This formation has a 90-year history of exploration and development and thousands of wellbore penetrations that have led to more accurate geologic mapping. The estimated proved reserves on our properties were approximately 20.6 MMBoe as of December 31, 2013 of which approximately 60.5% were classified as proved developed reserves. Of those proved developed reserves, 73.8% were comprised of oil and NGLs and 26.2% was natural gas. Average net daily production from our properties during the year ended December 31, 2013 was 3,658 Boe/d, which is comprised of 231 Bbl/d of oil, 7,574 Mcf/d of natural gas and 2,165 Bbl/d of NGLs. Based on net production from our properties for the year ended December 31, 2013, the total proved reserves associated with our properties had a reserve to production ratio of 15.4 years.
Our oilfield services segment specializes in increasing efficiencies and safety in drilling and completion processes, such as the installation and pressure testing of blowout 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.
Since blowout preventers are paramount for the safety of the field personnel and the environment of drilling locations, they must be tested and inspected on a regular basis. For the period November 12, 2013 to December 31, 2013 approximately 70% of revenue generated by our oilfield services segment was attributable to installation and pressure testing with the remaining 30% of revenue attributable to providing various auxiliary equipment that complements the blowout preventer. Virtually all of the segment’s revenue is derived from the U.S. land market areas. Demand for these services can change quickly and is primarily dependent on the number of wells drilled and completed. The segment has established operations in the central Mid-Continent, the west Texas Permian Basin, and the Eagle Ford shale of south Texas as a means to lessen exposure to localized volatility in drilling activity by having a footprint in various geographic basins.
How We Conduct Our Business and Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
| • | production volumes; |
| • | realized prices on the sale of natural gas, NGLs and oil, including the effect of our derivative contracts; |
| • | lease operating expenses; |
| • | Production and ad valorem taxes; |
| • | general and administrative expenses; and |
| • | Adjusted EBITDA. |
We commenced our oilfield services business in November 2013 with the acquisition of the MCE Entities. See “Note 2-Acquisition” in “Item 8 - Financial Statements and Supplementary Data” for further discussion of the MCE Acquisition. In addition to expanding the Partnership’s business to include oilfield services, the MCE Acquisition also expanded the geographic presence of our business, as the MCE Entities have an office in South Texas and West Texas, and expanded our customer base.
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In assessing the performance of our oilfield services segment, we will consider additional financial and operational metrics, including:
| • | Revenue; |
| • | Operating costs and expenses; and |
| • | Industry reportables related to safety requirements; |
Exploration and Production Segment
Production Volumes
Production volumes directly impact our results of operations. For more information about our production volumes, see “Results of Operations” below.
Realized Prices on the Sale of Natural Gas, NGLs and Oil
Factors affecting the sales price of our production. We sell our production to a variety of purchasers based on regional pricing. The relative prices we receive are determined by factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.
Natural gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The dry natural gas residue from our properties is transported and generally sold on index prices in the region. Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered and individual supply and demand dynamics at each location. Our natural gas production has historically sold at a negative basis differential from the NYMEX-Henry Hub price primarily due to the distance of the production attributable to our operating areas from the Henry Hub, which is located in Louisiana, and other location and transportation cost factors.
NGLs. Natural gas with a high energy content is referred to as “wet gas.” Certain of our properties produce wet gas, which has a higher value at the wellhead than natural gas with a lower energy content. Wet gas can be sold at the wellhead or, as is the case with our production, transported to a gas processing plant where the NGLs are separated from the wet gas leaving an NGL product called Y-Grade and dry gas residue. After processing, both the Y-Grade and dry gas residue are transported from or sold at a gas processing plant’s “tailgate.” The Y-Grade recovered from the processing of our wet gas is transported to Conway where it is fractionated into its five primary NGL components and sold based on posted prices.
When comparing prices received from production among producers in a region, it is important to compare wellhead prices as all producers have unique natural gas streams as well as unique contracts that take their natural gas to the sales markets. Because of our high energy content natural gas, we believe that our wellhead prices compare favorably with other natural gas producers with a lower energy content.
The wellhead Btu for our natural gas in the Golden Lane field has an average energy content of approximately 1,504 Btu, minimal sulfur and carbon dioxide content and generally receives a premium valuation. We have previously dedicated all NGLs and natural gas produced and sold from our wells operated by New Source Group in the Golden Lane field to Scissortail Energy, LLC, a subsidiary of Kinder Morgan Energy Partners (“Scissortail”), pursuant to a long-term gas sales contract entered into on May 1, 2005, between the contract operator and Scissortail. As part of the consideration for our long-term gas dedication, Scissortail constructed and owns a gas processing plant in Paden, Oklahoma, where the gas from the Golden Lane field is processed.
The produced natural gas from wells acquired in the March Acquisition in the Luther field has a wellhead Btu average energy content of approximately 1,260 Btu. The NGLs and natural gas produced from the Hunton in our wells operated by New Source Group in the Luther field is sold to DCP Midstream, LP (“DCP”), pursuant to a long-term gas contract entered on September 1, 2006 between the contract operator and DCP. Wells acquired in the Southern Dome Acquisition produce from the Arbuckle and the wellhead Btu for our natural gas has an average energy content of approximately 1,173 Btu. The NGLs and natural gas produced and sold from our wells operated by New Source Group in the Southern Dome field go to Scissortail Energy, LLC, pursuant to a long-term gas sales contract entered into between the contract operator and Scissortail on May 1, 2005.
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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 crude oil produced from our properties is sold to third-party marketing companies, presently United Petroleum Purchasing Company. These contracts are presently for terms of six months or less, which is customary for oil sales contracts.
Commodity Derivative Contracts. We enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. For additional information regarding our hedging policy, see “Liquidity and Capital Resources - Commodity Derivative Contracts.”
Production and Ad Valorem Taxes. Our production taxes are calculated as a percentage of our oil, natural gas, and NGL revenues, excluding the effects of our commodity derivative contracts. In general, as prices and volumes increase, our production taxes increase. Likewise, in general, as prices and volumes decrease, our production taxes decrease. Additionally, production tax rates vary by state, and as revenues by state vary, our production taxes will increase or decrease. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of our commodity derivative contracts. As a result we are forecasting our ad valorem taxes as a percentage of revenues, excluding the effects of our commodity derivative contracts.
General and Administrative Expenses. We and our general partner were parties to an omnibus agreement with New Source Energy through December 31, 2013, pursuant to which, among other things, New Source Energy provided management and administrative services that we believe were necessary to allow our general partner to operate, manage and grow our business. Through December 31, 2013, we incurred a quarterly fee of $675,000 for the provision of such services by New Source Energy. After December 31, 2013 our general partner provides the management and administrative services that we believe are necessary to allow us to operate, manage and grow our business. All actual direct and indirect expenses our general partner incurs will be reimbursed by us. Additionally, we are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit. Our general partner has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us. There is no assurance that general and administrative expenses will not increase substantially from the omnibus fees incurred in previous periods.
Lease Operating Expenses
Lease operating expenses are the costs incurred in the operation of producing properties and workover costs. Expenses for utilities, direct labor, water injection and disposal, and materials and supplies comprise the most significant portion of our lease operating expenses. Lease operating expenses do not include general and administrative expenses or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased lease operating expenses in periods during which they are performed.
Unlike typical oil and natural gas reservoirs, which show declining oil and gas production rates with time, the type of reservoir we currently target increases its oil and natural gas production rate over an initial period, and then, as the reservoir is depressurized, the wells assume a more typical decline curve. Similarly, the decline of saltwater volumes produced resembles the decline of hydrocarbon production following the peak production period. This reduces operating costs over time, in turn extending the economic life of the well and maximizing the hydrocarbon recovery from the reservoir.
We monitor our operations to ensure that we are incurring operating costs at the optimal level. Accordingly, we monitor our production expenses and operating costs per well to determine if any wells or properties should be shut in, recompleted or sold. We typically evaluate our oil and natural gas operating costs on a per Boe basis. This unit rate allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers.
Adjusted EBITDA
We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, non-cash compensation expense, acquisition related general and administrative expense, unrealized derivative gains and losses and other non-recurring gains and losses, such as our gain on investment in a subsidiary under common control and deferred financing costs.
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Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess:
| • | our operating performance as compared to that of other companies and partnerships in our industry, without regard to financing methods, capital structure or historical cost basis; |
| • | the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and |
| • | our ability to incur and service debt and fund capital expenditures. |
Adjusted EBITDA should not be considered an alternative to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner.
Oilfield Services Segment
Service Revenue. Our service revenue is generated based on the type of service we provide at an established hourly rate. The rate used varies depending on the service provided as well as the specific basin the service is dispatched from. In addition to our operations throughout the Mid-Continent region, we recently opened field offices in South Texas to focus on the Eagle ford Shale and in West Texas to focus on the Permian Basin.
Operating Costs and Expenses. 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.
Safety. Safety is an integral part of the performance metrics we have as a company to help manage our organization. Relative to operations safety is essential to maintain an effective and efficient service to our company while on their respective locations. Should an incident occur we are not able to work in an effective or efficient manner due to having to deal with the potential injured party or parties thus devaluing our position with our customer. From a financial perspective safety plays a vital role in the amount of insurance premiums the company is obligated to pay. The lower the safety score relative to incidents, the lower modification rate which is directly related to the class code burden per labor dollar spent.
Our company is further committed to safety by subscribing as members to ISNetworld and PEC which are industry wide organizations that are tasked by operators to manage the safety and health programs of their respective contractors. Both organizations work from a grading system that ultimately categorizes vendors into preferred vendors, secondary vendors, and those that do not a program suitable to the operator’s specifications that are removed from the roster. Our organization has been proud members since the inception of the company, and have gone through the training curriculum to have a qualified instructor on staff.
Outlook
North American crude oil and natural gas prices have historically been volatile based on supply and demand dynamics and we expect this volatility to continue into 2014. Factors that can affect the demand for our products and services include domestic and international economic conditions, the market price and demand for energy, the cost to develop natural gas and crude oil reserves in the U.S., along with state and federal regulation.
Although natural gas prices improved in 2013 compared to 2012, natural gas continues to be challenged due to an imbalance between supply and demand across North America. However, arctic air movements across North America during the early weeks of 2014 have caused natural gas demand to surge. As storage inventories have significantly declined in response to the recent weather conditions, natural gas prices have surpassed $5 per Mcf for the first time since the summer of 2010. Further helping demand, new uses of natural gas in industrial, power and other sectors will continue to help support price dynamics. Nevertheless, we still expect natural gas prices to be range-bound as natural gas supply continues to grow, particularly in the U.S. Looking to 2014, we expect natural gas prices will remain relatively consistent or possibly increase moderately from 2013 levels.
Similar to natural gas in recent years, a surge in the supply of NGLs has kept prices challenged. Ethane prices have decreased over time in terms of price per gallon and as a percentage relative to the price of crude oil on an energy equivalent basis. The decline in ethane prices is attributable to excess domestic inventories of this commodity. The current ethane
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oversupply situation may result in volatile ethane prices and prolonged periods of ethane rejection by producers and natural gas processors in an effort to balance supply and demand. U.S. LPG exports (propane and butane) continue to increase as a result of ample supplies and competitive prices. We expect 2014 NGLs prices will be range-bound and remain relatively flat compared to 2013.
Crude oil prices remained relatively stable throughout 2013, and oil continues to be more valuable than natural gas on a relative energy-equivalent basis. North American crude oil supply continues to increase due to the continued use of horizontal drilling technology throughout the U.S. and expansions of heavy oil production operations primarily in Canada. Global crude oil demand is expected to grow with supply in 2014. As crude oil supply grows, transportation capacity to downstream markets will be increasingly important. Bottlenecks and other transportation limitations may continue to add volatility among U.S. and Canadian grades of oil. However, we expect 2014 oil prices will remain relatively consistent with 2013.
Drilling activity forecast for 2014 is expected to remain robust in shale plays containing crude oil, condensate and NGL-rich natural gas production such as the Eagle Ford, Bakken, Niobrara, Mississippian, Wolfcamp, Woodford, Marcellus and Utica shales. Drilling activity in shale plays with predominantly dry natural gas reserves or natural gas reserves with a lower NGL content (e.g., the Haynesville/Bossier, Barnett, Fayetteville, Piceance and Jonah/Pinedale shales) are expected to remain well below peak levels.
As an oil and natural gas producer, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well or formation decreases. Our future growth will depend on our ability to continue to add estimated reserves in excess of our production. Accordingly, we plan to maintain our focus on adding reserves through development projects and improving the economics of producing oil and natural gas from the IPO Properties and our newly acquired properties. We expect further acquisition opportunities may come from New Source Energy as well as from unrelated third parties. Our ability to add estimated reserves through acquisitions and development projects is dependent on many factors including our ability to raise capital, obtain regulatory approvals and procure contract drilling rigs and personnel.
As an oilfield services provider, our business depends in part 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 central Oklahoma, the Permian Basin in West Texas and the Eagle Ford shale in South Texas. 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 and natural gas prices. Companies in the energy services industry have historically tended to delay capital equipment projects, including maintenance and upgrades, during industry downturns, which has been characterized by excess equipment capacity across the U.S. hydraulic fracturing market.
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Results of Operations
Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012
The following table presents selected financial and operating information. Comparative results of operations for the periods indicated are discussed below:
| Year Ended December 31, | Percent | |||||||||||||
| 2013 | 2012 | Change | Change | |||||||||||
| Statement of Operations (in thousands, except percent change): | ||||||||||||||
| Oil sales | $ | 8,090 | $ | 5,570 | $ | 2,520 | 45 | % | ||||||
| Natural gas sales | 10,000 | 6,030 | 3,970 | 66 | % | |||||||||
| Natural gas liquids sales | 28,847 | 23,996 | 4,851 | 20 | % | |||||||||
| Service and rentals | 3,738 | — | 3,738 | 100 | % | |||||||||
| Total revenues | 50,675 | 35,596 | 15,079 | 42 | % | |||||||||
| Lease operating expenses | 12,631 | 4,965 | 7,666 | 154 | % | |||||||||
| Production taxes | 2,669 | 1,144 | 1,525 | 133 | % | |||||||||
| Cost of providing service and rentals | 2,040 | — | 2,040 | 100 | % | |||||||||
| Total production and oilfield services expenses | 17,340 | 6,109 | 11,231 | 184 | % | |||||||||
| General and administrative | 14,760 | 12,660 | 2,100 | 17 | % | |||||||||
| Depreciation, depletion, and amortization | 18,556 | 14,409 | 4,147 | 29 | % | |||||||||
| Accretion expense | 209 | 116 | 93 | 80 | % | |||||||||
| Loss on disposal of fixed assets | — | — | — | 100 | % | |||||||||
| Total operating expenses | 50,865 | 33,294 | 17,571 | 53 | % | |||||||||
| Operating income (loss) | (190 | ) | 1,050 | (1,240 | ) | (118 | )% | |||||||
| Other income (expense): | ||||||||||||||
| Interest expense | (4,078 | ) | (3,202 | ) | (876 | ) | 27 | % | ||||||
| Net gain (loss) on commodity derivatives | (5,548 | ) | 7,057 | (12,605 | ) | (179 | )% | |||||||
| Gain on investment in subsidiary under common control | 22,709 | — | 22,709 | 100 | % | |||||||||
| Other income | 1,603 | — | 1,603 | 100 | % | |||||||||
| Income before income taxes | 14,496 | 4,905 | 9,591 | 196 | % | |||||||||
| Income tax (expense) benefit | 12,126 | (1,796 | ) | 13,922 | (775 | )% | ||||||||
| Net income | $ | 26,622 | $ | 3,109 | $ | 23,513 | 756 | % | ||||||
| Sales Volumes: | ||||||||||||||
| Crude oil (Bbls) | 84,273 | 61,010 | 23,263 | 38 | % | |||||||||
| Natural gas (Mcf) | 2,764,336 | 2,278,342 | 485,994 | 21 | % | |||||||||
| Natural gas liquids (Bbls) | 790,234 | 711,195 | 79,039 | 11 | % | |||||||||
| Total crude oil equivalent (Boe)(1) | 1,335,230 | 1,151,929 | 183,301 | 16 | % | |||||||||
| Average Sales Price (Excluding Derivatives): | ||||||||||||||
| Crude oil (per Bbl) | $ | 95.14 | $ | 91.30 | $ | 3.84 | 4 | % | ||||||
| Natural gas (per Mcf) | $ | 3.61 | $ | 2.65 | $ | 0.96 | 36 | % | ||||||
| Natural gas liquids (per Bbl) | $ | 36.50 | $ | 33.74 | $ | 2.76 | 8 | % | ||||||
| Average Sales Price (per Boe) | $ | 35.15 | $ | 30.90 | $ | 4.25 | 14 | % | ||||||
| Average Production Costs (per Boe)(2): | $ | 9.46 | $ | 5.40 | $ | 4.06 | 75 | % | ||||||
| (1) | Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. |
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| (2) | Includes lease operating expense and workover expense. |
Revenues from our operations were approximately $50.7 million for the year ended December 31, 2013, an increase of $15.1 million, or 42%, compared to the year ended December 31, 2012. Of the total revenues generated during 2013, approximately 57% were generated through NGL sales, approximately 20% were generated through natural gas, approximately 16% were generated through oil sales and approximately 7% of sales were generated through service and rental revenues. The increase in revenues during 2013 was largely the result of commodity price increases as well as the acquisitions of oil and gas properties throughout 2013 and the acquisition of MCE.
The following were specifically related to the impact of production and price levels on revenues recorded during the periods:
| • | the average realized oil price was $95.14 per Bbl during the year ended December 31, 2013, an increase of 4% from $91.30 per Bbl during the year ended December 31, 2012; |
| • | total oil production was 84,273 Bbls during the year ended December 31, 2013, an increase of 38% from 61,010 Bbls during the year ended December 31, 2012. The increase was primarily due to acquisitions of the oil and gas properties through 2013, which primarily related to the Southern Dome Acquisition that had a higher oil concentration. |
| • | the average realized natural gas price was $3.61 per Mcf during the year ended December 31, 2013, an increase of 36% from $2.65 per Mcf during the year ended December 31, 2012; |
| • | total natural gas production was 2,764,336 Mcf for the year ended December 31, 2013, an increase of 21% from 2,278,342 Mcf for the year ended December 31, 2012; |
| • | the average realized NGLs price was $36.50 per Bbl during the year ended December 31, 2013, an increase of 8% from $33.74 per Bbl during the year ended December 31, 2012; |
| • | total NGLs production was 790,234 Bbls for the year ended December 31, 2013, an increase of 11% from 711,195 Bbls for the year ended December 31, 2012; and |
| • | service and rental revenues from our oilfield services segment were $3.7 million for the period from November 12, 2013 (the acquisition date) to December 31, 2013. |
Operating Expenses
Lease operating expenses. Lease operating expenses increased $7.7 million, or 154%, to $12.6 million in 2013 from $5.0 million in 2012 primarily due to the acquisition of oil and gas properties and increased operator fees and vendor costs.
Production taxes. Production taxes increased $1.5 million, or 133%, to $2.7 million in 2013 from $1.1 million in 2012. The increase was primarily related to the acquisition of oil and gas properties and higher realized oil and gas prices.
Costs of providing services and rentals (excluding depreciation). The cost of providing services and rentals in our MCE Entities was $2.0 million for the year ended December 31, 2013.
General and administrative. General and administrative expense increased $2.1 million, or 17%, to $14.8 million in 2013 from $12.7 million in 2012. The increase in general and administrative expense was primarily attributable to the acquisition of MCE where the Partnership has consolidated MCE's general and administrative expenses from November 12, 2013 to December 31, 2013. In addition, the increase is due to an increase in acquisition-related costs related to the acquisition of oil and gas properties in 2013 as compared to 2012. In historical periods, the general and administrative expenses reflect an allocation of New Source Energy’s general and administrative expenses based on the proportion of historical production attributable to the IPO Properties. Through December 31, 2013, we were parties to an omnibus agreement, whereby we paid New Source Energy a quarterly fee of $675,000 for the provision of management and administrative services. Effective January 1, 2014, in lieu of the quarterly fee, our general partner will be reimbursed by us for the actual direct and indirect expenses it incurs in its performance. There is no assurance that general and administrative expenses will not increase substantially from the omnibus fees incurred in previous periods.
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New Source Energy incurred $6.1 million in general and administrative expenses as of December 31, 2013, on behalf of the Partnership. These expenses were included in the quarterly fee under the omnibus agreement mentioned above of which the Partnership paid New Source Energy paid $2.4 million for the year ended December 31, 2013.
Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $4.1 million, or 29%, to $18.6 million in 2013 from $14.4 million in 2012. In historical periods, prior to our IPO, depreciation, depletion and amortization expense reflects an allocation of New Source Energy’s depreciation, depletion and amortization based on the proportion of historical production attributable to the IPO Properties. In 2013, depreciation, depletion and amortization expense was computed by using specific production, reserves and future development costs directly attributable to the Partnership’s properties.
Other Income/Expense
Interest expense. 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 in 2013 and write-off of loan fees.
Realized and unrealized losses from derivatives. Realized and unrealized losses from derivatives were $5.5 million in 2013 compared to gains of $7.1 million in 2012. The change in realized and unrealized derivative gains and losses 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.
Other income related to Contingent consideration payable to related parties. The Partnership recognized other income of $1.6 million related the change of the estimated fair value of the contingent consideration related to the Southern Dome Acquisition.
Income Taxes
Income tax benefit was $12.1 million 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, 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.
Net Income (Loss)
We recorded net income of $26.6 million in 2013 compared to a net income of $3.1 million in 2012, primarily due to a change in entity status under the Internal Revenue Code, the gain realized on the acquisition of MCE, increase in revenues, offset by an increase in operating expenses, an increase in interest expense, and realized and unrealized losses on derivatives.
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Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011
The following table presents selected financial and operating information. Comparative results of operations for the periods indicated are discussed below:
| Year Ended December 31, | Percent | |||||||||||||
| 2012 | 2011 | Change | Change | |||||||||||
| Statement of Operations (in thousands, except percent change): | ||||||||||||||
| Oil sales | $ | 5,570 | $ | 4,489 | $ | 1,081 | 24 | % | ||||||
| Natural gas sales | 6,030 | 8,713 | (2,683 | ) | (31 | )% | ||||||||
| Natural gas liquids sales | 23,996 | 33,058 | (9,062 | ) | (27 | )% | ||||||||
| Total revenues | 35,596 | 46,260 | (10,664 | ) | 30 | % | ||||||||
| Lease operating expenses | 4,965 | 5,551 | (586 | ) | (11 | )% | ||||||||
| Workover expenses | 1,252 | 2,324 | (1,072 | ) | (46 | )% | ||||||||
| Production taxes | 1,144 | 2,155 | (1,011 | ) | (47 | )% | ||||||||
| Total production expenses | 7,361 | 10,030 | (2,669 | ) | 36 | % | ||||||||
| General and administrative | 12,660 | 6,928 | 5,732 | 83 | % | |||||||||
| Depreciation, depletion, and amortization | 14,409 | 14,738 | (329 | ) | (2 | )% | ||||||||
| Accretion expense | 116 | 55 | 61 | 111 | % | |||||||||
| Total operating expenses | 34,546 | 31,751 | 2,795 | (8 | )% | |||||||||
| Operating income | 1,050 | 14,509 | 13,459 | 1,282 | % | |||||||||
| Other income (expense): | ||||||||||||||
| Interest expense | (3,202 | ) | (3,735 | ) | 533 | (14 | )% | |||||||
| Net gain (loss) on commodity derivatives | 7,057 | (1,349 | ) | 8,406 | (623 | )% | ||||||||
| Income before income taxes | 4,905 | 9,425 | (4,520 | ) | (48 | )% | ||||||||
| Income tax expense | (1,796 | ) | (10,502 | ) | 8,706 | (83 | )% | |||||||
| Net income (loss) | $ | 3,109 | $ | (1,077 | ) | $ | 4,186 | (389 | )% | |||||
| Sales Volumes: | ||||||||||||||
| Crude oil (Bbls) | 61,010 | 48,770 | 12,240 | 25 | % | |||||||||
| Natural gas (Mcf) | 2,278,342 | 2,378,232 | (99,890 | ) | (4 | )% | ||||||||
| Natural gas liquids (Bbls) | 711,195 | 720,615 | (9,420 | ) | (1 | )% | ||||||||
| Total crude oil equivalent (Boe)(1) | 1,151,929 | 1,165,757 | (13,828 | ) | (1 | )% | ||||||||
| Average Sales Price (Excluding Derivatives): | ||||||||||||||
| Crude oil (per Bbl) | $ | 91.30 | $ | 92.04 | $ | (0.74 | ) | (1 | )% | |||||
| Natural gas (per Mcf) | $ | 2.65 | $ | 3.66 | $ | (1.01 | ) | (28 | )% | |||||
| Natural gas liquids (per Bbl) | $ | 33.74 | $ | 45.87 | $ | (12.13 | ) | (26 | )% | |||||
| Average Sales Price (per Boe) | $ | 30.90 | $ | 39.68 | $ | (8.78 | ) | (22 | )% | |||||
| Average Production Costs (per Boe)(2): | $ | 5.40 | $ | 6.76 | $ | (1.36 | ) | (20 | )% | |||||
| (1) | Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. |
| (2) | Includes lease operating expense and workover expense. |
Oil, Natural Gas and NGL Revenues
Revenues from oil and natural gas operations were approximately $35.6 million for the year ended December 31, 2012, a decrease of $10.7 million, or 30%, compared to the year ended December 31, 2011. Of the total revenues generated during
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2012, approximately 67% were generated through NGL sales, approximately 17% were generated through natural gas sales and approximately 16% were generated through oil sales. The decrease in revenues during 2012 was largely the result of significantly lower average prices of natural gas and NGLs, which were 28% and 26% lower, respectively, than those of 2011. Average oil prices were 1% lower than 2011. Crude oil production was higher by 25% while natural gas and NGL production volumes were lower by 4% and 1%, respectively.
The following were specifically related to the impact of production and price levels on revenues recorded during the periods:
| • | the average realized oil price was $91.30 per Bbl during the year ended December 31, 2012, a decrease of 1% from $92.04 per Bbl during the year ended December 31, 2011; |
| • | total oil production was 61,010 Bbls during the year ended December 31, 2012, an increase of 25% from 48,770 Bbls during the year ended December 31, 2011 primarily because we were developing and producing from a portion of the Hunton reservoir containing a higher concentration of oil; |
| • | the average realized natural gas price was $2.65 per Mcf during the year ended December 31, 2012, a decrease of 28% from $3.66 per Mcf during the year ended December 31, 2011; |
| • | total natural gas production was 2,278,342 Mcf for the year ended December 31, 2012, a decrease of 4% from 2,378,232 Mcf for the year ended December 31, 2011; |
| • | the average realized NGLs price was $33.74 per Bbl during the year ended December 31, 2012, a decrease of 26% from $45.87 per Bbl during the year ended December 31, 2011; and |
| • | total NGLs production was 711,195 Bbls for the year ended December 31, 2012, a decrease of 1% from 720,615 Bbls for the year ended December 31, 2011. |
Operating Expenses
Lease operating expenses. Lease operating expenses decreased $0.6 million, or 11%, to $5.0 million in 2012 from $5.6 million in 2011 due to fewer repairs and tighter control of costs.
Workover expenses. Workover expenses decreased $1.1 million, or 46%, to $1.2 million in 2012 from $2.3 million in 2011 due to fewer required workovers needed in 2012. Production costs (including workover expenses) decreased on an equivalent basis from $6.76 per Boe to $5.40 per Boe.
Production taxes. Production taxes decreased $1.0 million, or 47%, to $1.1 million in 2012 from $2.1 million in 2011. The decrease was primarily related to increased tax incentives for production from new horizontal wells and lower realized sales prices.
General and administrative. General and administrative expense increased $5.7 million, or 83%, to $12.6 million in 2012 from $6.9 million in 2011. The increase in general and administrative expense was primarily attributable to an increase in staffing costs and accounting and legal fees in 2012 as compared to 2011, in addition to $8.2 million of stock-based compensation expense incurred in 2012 compared to $4.5 million of stock-based compensation expense in 2011. In historical periods, the general and administrative expenses reflect an allocation of New Source Energy’s general and administrative expenses based on the proportion of historical production attributable to the IPO Properties. Through December 31, 2013, we will pay New Source Energy a quarterly fee of $675,000 for the provision of management and administrative services. After December 31, 2013, in lieu of the quarterly fee, our general partner will reimburse New Source Energy, on a quarterly basis, for the actual direct and indirect expenses it incurs in its performance under the omnibus agreement, and we will reimburse our general partner for such payments it makes to New Source Energy. There is no assurance that general and administrative expenses will not increase substantially from the omnibus fees incurred in previous periods.
Depreciation, depletion and amortization. DD&A expense decreased $0.3 million, or 2%, to $14.4 million in 2012 from $14.7 million in 2011. In historical periods, DD&A expense reflects an allocation of New Source Energy’s depreciation, depletion and amortization based on the proportion of historical production attributable to the IPO Properties.
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Other Income/Expense
Interest expense. Interest expense decreased $0.5 million, or 14%, to $3.2 million in 2012 from $3.7 million in 2011. The decrease was primarily due to the write off of loan fees of $0.7 million related to the refinancing of New Source Energy’s credit facility in 2011.
Realized and unrealized losses from derivatives. Realized and unrealized gains from derivatives were $7.1 million in 2012 compared to losses of $1.3 million in 2011. The change in realized and unrealized derivative gains and losses is primarily the result of lower natural gas and NGLs settlement and futures prices in the 2012 period compared with the 2011 period. In July 2012, we liquidated all of our oil, natural gas and 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.
Income Taxes
Income tax expense was $1.8 million in 2012 compared to $10.5 million for the 2011. The IPO Properties were owned by a company that became a tax paying entity on August 11, 2011 and incurred deferred income taxes based on the differences in book and tax basis of the properties at that date.
Net Income (Loss)
We recorded net income of $3.1 million in 2012 compared to a net loss of $1.1 million in 2011, primarily due to derivative gains of $7.1 million in 2012, partially offset by lower revenues and by higher general and administrative costs and effects of income taxes in 2011 related to the change in tax status of the IPO Properties.
Capital Resources and Liquidity
Our primary sources of liquidity and capital resources are cash flows generated by operating activities and borrowings under our revolving credit facility. We may also have the ability to issue additional equity and debt securities as needed. To date, our primary use of capital has been for the acquisition and development of oil and natural gas properties and the acquisition of our oilfield services business through the MCE Acquisition.
Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions.
We may borrow to make distributions to our unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. In addition, we plan to hedge a significant portion of our production. We generally are required to settle our commodity hedge derivatives within five days of the end of the month. As is typical in the oil and natural gas industry, we do not generally receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the contracts, we are required to pay the derivative counterparty the difference between the fixed price in the commodity derivative contract and the market price before we receive the proceeds from the sale of the hedged production. If this occurs, we may make working capital borrowings to fund our distributions. Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production, and as a result, we may not grow as quickly as other oil and natural gas entities or at all.
We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. Because our proved reserves and production decline continually over time and because we own a limited amount of undeveloped properties, we may need to make acquisitions to sustain our level of distributions to unitholders over time.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our revolving
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credit facility, issuances of debt and equity securities or from other sources, such as asset sales. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our revolving credit facility or other future indebtedness. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.
Cash Flows Provided by Operating Activities
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, and an increase in the length of our drilling cycles, combined with increases in production costs and general and administrative expenses. Cash provided by operating activities is impacted by the prices received for oil and natural gas sales and levels of production. Production volumes in the future will in large part be dependent upon the amount of and results of future capital expenditures. Future levels of capital expenditures may vary due to many factors, including drilling results, oil, natural gas and NGL prices, industry conditions, prices and availability of goods and services and the extent to which proved properties are acquired.
Cash Flows Used in Investing and Financing Activities
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. Cash flows used in investing activities are related to acquisitions and development of our oil and gas properties. The increase in cash flows used in investing activities is primarily due to the acquisitions of oil and gas properties 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. Financing cash flows are primarily related to debt and equity financing of the property development and working capital. 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 totaled $3.7 million and $3.7 million at December 31, 2013 and 2012, respectively. The slight decrease in working capital is primarily due to an increase in derivative obligations and other general short-term obligations offset by an increase in cash and receivables in 2013. The collection of receivables has historically been timely. Historically, losses associated with uncollectible receivables have not been significant. We had no cash and cash equivalents at December 31, 2012 due to the carve-out nature of the financial statements presented.
Capital Expenditures
Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain the revenue generating capabilities of our assets at current levels over the long term. For the year ended December 31, 2013, our maintenance capital expenditures were $9.3 million.
As described in Note 2 to the financial statements, we completed the acquisition of the MCE Entities, a pressure-testing and tool rental business, on November 12, 2013. We are still in the process of evaluating the estimated annual maintenance capital expenditures associated with the acquired business. During the first two months of 2014, we have ordered 11 additional pressure trucks. However, depending on growth trends in our areas of operations, additional equipment may be necessary.
Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The primary purpose of growth capital is to acquire producing assets that will increase our distributions per unit and secondarily increase the rate of development and production of our existing properties in a manner which is expected to be accretive to our unitholders. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. We expect to primarily rely upon external financing sources, including commercial bank borrowings and the issuance of debt and equity interests, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions. We are party to other operating agreements pursuant to which the operator could decide to engage in capital spending that would require us to pay our share or suffer substantial penalties
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Based on our current oil, natural gas and NGL price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our revolving credit facility will exceed our planned capital expenditures and other cash requirements for the year ending December 31, 2014. However, future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.
Private Placement
On December 20, 2013, we completed a private placement of 465,000 common units pursuant to a common unit purchase agreement between the Partnership and Goldman Sachs MLP Income Opportunities Fund (the “Purchaser”), dated December 17, 2013. We sold 465,000 common units in the Private Placement at a negotiated purchase price of $21.15 per common unit, resulting in approximately $9.8 million in proceeds to us, which were used for operations.
Revolving Credit Facility
In connection with our IPO, we entered into a revolving credit facility by and among us, as borrower, the Bank of Montreal, as administrative agent for the lenders party thereto, and the other lenders party thereto. The revolving credit facility is a four-year, senior secured revolving credit facility. In addition, we assumed approximately $70.0 million of New Source Energy’s indebtedness under its credit facility attributable to the IPO Properties. We used a portion of the net proceeds from our initial public offering, together with $15.0 million of borrowings under our revolving credit facility to (i) repay in full such assumed debt and (ii) make a distribution to New Source Energy as partial consideration for the contribution by New Source Energy of the IPO Properties and certain commodity derivative contracts. As additional consideration for its contribution of the IPO Properties to us in connection with the IPO, we issued a $25.0 million note payable to New Source Energy, which we subsequently repaid in full.
Our revolving credit facility is reserve-based, permitting us to borrow an amount up to the borrowing base, which is primarily based on the value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, NGL and oil reserves, which will take into account the prevailing natural gas, NGL and oil prices at such time, as adjusted for the impact of our derivative contracts. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of (i) a decrease in our borrowing base due to a subsequent borrowing base redetermination, or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.
A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we will be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our revolving credit facility. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our revolving credit facility.
On February 28, 2013, we entered into a First Amendment (the “First Amendment”) to our revolving credit facility, which added a lender, increased our borrowing base from $30.0 million to $60.0 million, and increased the lenders’ aggregate commitment from $60.0 million to $150.0 million. As a condition precedent to effectiveness of the First Amendment, we repaid the $25.0 million subordinated note issued to New Source Energy in full with borrowings under our revolving credit facility. On June 25, 2013, the Partnership entered into a Second Amendment (the “Second Amendment”) to our revolving credit facility. The Second Amendment added two lenders and increased the Partnership’s borrowing base from $60.0 million to $75.0 million. On October 29, 2013, the Partnership entered into a Third Amendment (the “Third Amendment”) to its Credit Agreement. The Third Amendment (i) adds a lender under the Credit Agreement, and (ii) increases the Partnership’s borrowing base under the Credit Agreement from $75 million to $87.5 million. On November 12, 2013, the Partnership entered into a Fourth Amendment (the “Fourth Amendment”) to its Credit Agreement. The Fourth Amendment amends certain provisions of the Credit Agreement with respect to the transactions contemplated by the contribution agreement governing the MCE Acquisition. The Fourth Amendment, among other things, provides that (i) neither of the MCE Entities is a “Subsidiary” for the purposes of the Credit Agreement, (ii) the Partnership may include actual cash dividends paid by MCE LP to the Partnership in the Partnership’s calculation of financial covenants, (iii) the Partnership may use proceeds of the Credit Agreement to make permitted Investments in the MCE Entities and (iv) future Investments in the MCE Entities may be made (a) with proceeds of the sales of the Partnership’s common units or (b) in an amount not to exceed $5.0 million in any twelve month period (without
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regard to any investments made pursuant to clause (a)), in each case, subject to certain limitations. As of December 31, 2013, we had approximately $78.5 million of outstanding borrowings under our revolving credit facility.
Borrowings under the revolving credit facility bear interest at a base rate (a rate based off of the higher of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) LIBOR plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to our borrowing base utilization). Interest will be payable quarterly, or if LIBOR applies, it may be payable at more frequent intervals. In addition, the unused portion of our revolving credit facility is subject to a commitment fee of 0.50%.
The revolving credit facility requires us to maintain a minimum interest coverage ratio of not less than 2.50 to 1.00, a current ratio of not less than 1.0 to 1.0 and a ratio of total debt to EBITDA of not more than 3.50 to 1.00. In addition, the credit agreement governing the revolving credit facility contains customary affirmative and negative covenants for transactions of this nature, including, but not limited to restrictions on: (i) incurrence of debt and liens (in each case, subject to certain exceptions); (ii) investments, acquisitions, mergers and asset sales (in each case, subject to certain exceptions); (iii) payments of dividends and distributions (with exceptions for distributions of available cash consistent with the partnership agreement, so long as (a) no event of default has occurred and is continuing, or would result there from, and (b) our borrowing base utilization does not exceed 90%) and (iv) certain modifications to organizational documents and material agreements, subject to certain exceptions. If we should fail to perform our obligations under these and other covenants, the revolving commitments could terminate and any outstanding borrowings under the revolving credit agreement, together with accrued interest, could become immediately due and payable. At December 31, 2013, we were in compliance with all covenants of the revolving credit facility.
Note Payable
In connection with our IPO we issued a $25.0 million note payable to New Source Energy as partial consideration for its contribution of the IPO Properties to us. On February 28, 2013, this note was paid in full with borrowings under our revolving credit facility.
MCE Debt
MCE has financing notes with various lending institutions for certain property and equipment. These notes range from 36-60 months in duration and mature May 2016 through April 2018 and carry interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets and are secured by the specific assets being financed.
Contractual Obligations
A summary of our contractual obligations as of December 31, 2013 is provided in the following table (in thousands).
| Obligations Due in Period | |||||||||||
| Contractual Obligation | 2014 | 2015 | 2016 | 2017 | 2018 | Total | |||||
| Long-term debt | $719 | $766 | $558 | $78,651 | $39 | $80,733 | |||||
| Interest on long-term debt and credit facility (1) | 2,691 | 2,646 | 2,598 | 2,563 | 2 | 10,500 | |||||
| Operating leases | 175 | 88 | 3 | — | — | 266 | |||||
| Total contractual obligations | $3,585 | $3,500 | $3,159 | $81,214 | $41 | $91,499 | |||||
| (1) | Estimated interest using the actual weighted average interest rate of the Partnership's revolving credit facility of 3.25% and a weighted average interest rate on the MCE debt of 6.27% as of December 31, 2013. This rate is variable and could change in the future; however, we believe this is a reasonable estimate considering recent Federal Reserve interest rate policy. |
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, 2013 is $3.5 million.
We are party to a development agreement pursuant to which we have agreed to maintain an annual maintenance drilling budget averaging no less than $8.2 million through 2016 and New Dominion has agreed to use its commercially reasonable
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best efforts to conduct its operations such that the Partnership’s proportionate share of capital expenses that we would consider maintenance capital pursuant to the Golden Lane Participation Agreement is equal to the annual maintenance drilling budget set by our general partner. Additionally, through December 31, 2013, we paid New Source Energy a quarterly fee of $675,000 for the provision of administrative, managerial and operating services. For more information regarding such agreements, see “Item 13 - Certain Relationships and Related Transactions, and Director Independence-Related Party Agreements - Golden Lane Participation Agreement” and “Development Agreement.”
Commodity Derivative Contracts
Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, natural gas and NGL prices. Oil, natural gas and NGL prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on oil, natural gas and NGL prices and our ability to maintain and increase production through acquisitions and exploitation and development projects.
To mitigate a portion of its exposure to fluctuations in commodity prices, the Partnership enters into commodity price risk management activities with respect to a portion of projected crude oil, natural gas and NGLs production through commodity price swaps, collars, and put options (collectively “derivatives”). Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas due to the geographic price differentials between a given cash market location and the futures contract delivery locations. Settlement or expiration of the hedges is designed to coincide as closely as possible with the physical sale of the commodity being hedged—daily for oil and monthly for natural gas—to obtain reasonable assurance that a gain in the cash sale will offset the loss on the hedge and vice versa.
Our hedging strategy includes entering into commodity derivative contracts covering approximately 50% to 90% of our estimated total production over a three-to-five year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a derivative contract is terminated prior to its expiration. See Note 11 to the consolidated financial statements for more information.
Critical Accounting Policies and Estimates
Investors in our partnership should be aware of how certain events may impact our financial results based on the accounting policies in place. In our management’s opinion, the more significant reporting areas impacted by our management’s judgments and estimates are revenue recognition, the choice of accounting method for oil and natural gas activities, oil and natural gas reserve estimation, impairment of long-lived assets and valuation of equity-based compensation. Our management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known.
The selection and application of accounting policies are an important process that changes as our business changes and as accounting rules are developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment to the specific set of circumstances existing in our business. The policies we consider to be the most significant are discussed below.
Oil and Natural Gas Properties
The accounting for our business is subject to special accounting rules that are unique to the oil and natural gas industry. There are two allowable methods of accounting for oil and natural gas business activities: the successful efforts method and the full-cost method. We utilize the full-cost method of accounting, under which all costs associated with property acquisition, exploration and development activities are capitalized. We also have the ability to capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.
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Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of oil and natural gas properties are generally calculated on a well by well or lease or field basis. Additionally, gain or loss may generally be recognized on sales of oil and natural gas properties under the successful efforts method. As a result, our financial statements will differ from companies that apply the successful efforts method, since we will generally reflect a higher level of capitalized costs, as well as a higher oil and natural gas depreciation, depletion and amortization rate, and we will not have exploration expenses that successful efforts companies frequently have.
Under the full-cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. Proceeds from the sale of properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unevaluated properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties, and otherwise if impairment has occurred.
We review the carrying value of our oil and natural gas properties under the full-cost accounting rules of the SEC on a quarterly basis. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues, less estimated future expenditures to be incurred in developing and producing the proved reserves and less any related income tax effects.
Two primary factors impacting this test are reserve levels and oil and natural gas prices and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value, less deferred income taxes, is written off as an expense.
Oil, Natural Gas Liquids and Natural Gas Reserve Quantities
Proved reserves are defined by the SEC as those volumes of crude oil, condensate, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are volumes expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. We rely upon various assumptions in our estimation of proved reserves, including in the case of proved undeveloped reserves that we will participate fully in the development of our undeveloped properties pursuant to the terms of the applicable operating agreement. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of additional assumptions based on professional judgment. Estimated reserves are often subject to future revisions, certain of which could be substantial, based on the availability of additional information, including reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil, natural gas and NGL prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.
Derivative Instruments
We use commodity price and financial risk management instruments to mitigate our exposure to fluctuations in oil, natural gas and NGL prices. Recognized gains and losses on derivative contracts are reported as a component of the related transaction. Results of oil and natural gas derivative contract settlements and the changes in the fair value of derivative instruments that occur prior to maturity are reflected in other income in the statement of operations. Accounting guidance for derivatives and hedging establishes accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded at fair value and included in the balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated as oil and natural gas cash flow hedges, changes in fair value, to the extent the hedge is effective, are to be recognized in other comprehensive income until the hedged item is recognized in earnings as oil and natural gas sales. Any change in the fair value
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resulting from ineffectiveness is recognized immediately as gains or losses in the statement of operations. All derivative instruments are recognized as either assets or liabilities in the balance sheet at fair value. None of such instruments have been designated as cash flow hedges. Accordingly, changes in the fair value of all derivative instruments have been recorded in the statements of operations.
One of the primary factors that can have an impact on our results of operations is the method used to value our derivatives. We have established the fair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors.
Another factor that can impact our results of operations each period is our ability to estimate the level of correlation between future changes in the fair value of the hedge instruments and the transactions being hedged, both at inception and on an ongoing basis. This correlation is complicated since energy commodity prices, the primary risk we hedge, have quality and location differences that can be difficult to hedge effectively. The factors underlying our estimates of fair value and our assessment of correlation of our hedging derivatives are impacted by actual results and changes in conditions that affect these factors, many of which are beyond our control.
Revenue Recognition
Oil and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil and natural gas sales such that revenues are recognized based on the share of actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage.
Equity-Based Compensation
Equity-based compensation awards are recognized in the financial statements as the cost of services received in exchange for awards of equity instruments based on the fair value of those awards at their grant date. If an award has a fixed vesting date, the cost is recognized over the period from the grant date to the vesting date(s) of the award. If an award does not have a fixed vesting date, the cost is recognized at the time it vests.
The fair value of equity awards is determined utilizing such factors as the actual and projected financial results, the principal amount of indebtedness, valuations based on financial and reserve report multiples of comparable companies, control premium, marketability considerations, valuations performed by third parties, and other factors we believe are material to the valuation process. The values reported in the financial statements are as of a point in time and do not reflect subsequent changes in market conditions and other factors.
Valuations related to business acquisitions
Valuations of businesses acquired are accounted for under the acquisition method of accounting. The acquisition method requires (a) determining the acquisition date; (b) recognizing and measuring at the acquisition date the fair value of the identifiable assets acquired, the liabilities assumed, and any non-controlling interest; and (c) recognizing and measuring goodwill. The Partnership used a third-party valuation specialist to assist in determining the fair value for the total consideration, the assets acquired and the liabilities assumed as of the acquisition date.
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 and 2013. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy, and we expect to experience inflationary pressure on the cost of oilfield services and equipment when increasing oil, natural gas and NGL prices increase drilling activity in our areas of operations.
Off-Balance Sheet Arrangements
Currently, we do not have any off-balance sheet arrangements.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our major market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Realized pricing is primarily driven by the spot market prices applicable to our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile for several years, and we expect this volatility to continue in the future. The prices we receive for our oil, natural gas and NGL production depend on many factors outside of our control, including:
| • | developments generally impacting significant oil-producing countries and regions, such as Iraq, Iran, Syria, and Libya, the gulf coast and offshore South and Central America, Alaska and onshore U.S.; |
| • | the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to continue to manage oil supply through export quotas; |
| • | the overall demand for oil and natural gas in the United States and abroad; |
| • | volatility in the U.S. and global economies; |
| • | weather conditions; and |
| • | new and changing legislation and regulatory philosophy in the U.S. |
Any declines in oil, natural gas and NGL prices may have an adverse impact on our financial condition, results of operations and capital resources. If oil prices decline by $10.00 per Bbl, then our Standardized Measure as of December 31, 2013 would have been lower by approximately $7.6 million. If NGLs prices decline by $5.00 per Bbl, then our Standardized Measure as of December 31, 2013 would decrease by approximately $31.0 million. If natural gas prices decline by $1.00 per Mcf, then our Standardized Measure as of December 31, 2013 would decrease by approximately $20.7 million.
In order to reduce the impact of fluctuations in oil, natural gas and NGL prices on our revenues, or to protect the economics of property acquisitions, we intend to periodically enter into derivative contracts with respect to a significant portion of our estimated oil and natural gas production through various transactions that fix the future prices received. These transactions may include price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. Additionally, we may enter into collars, whereby we receive the excess, if any, of the fixed floor over the floating rate or we pay the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil, natural gas and NGL prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations.
Swaps. In a typical commodity swap agreement, we receive the difference between a fixed price per unit of production and a price based on an agreed upon published third-party index, if the index price is lower than the fixed price. If the index price is higher, we pay the difference. By entering into swap agreements, we effectively fix the price that we will receive in the future for the hedged production. Our swaps are settled in cash on a monthly basis.
Put Options. In a typical put option arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices. Our put options are exercised in cash on a monthly basis only when the floor price exceeds the reference price, otherwise they expire unsettled.
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Collars. In a typical collar arrangement, we receive the excess, if any, of the contract floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the contract ceiling price. Our collars are exercised in cash on a monthly basis only when the reference price is outside of floor and ceiling prices (the collar), otherwise, they expire unsettled.
The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected requiring market purchases to meet commitments, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform according to the hedging arrangement. To the extent that we engage in hedging activities, we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly insulated against decreases in such prices.
Presently, all of our hedging arrangements are with two counterparties, one of which is a lender under our revolving credit facility. If these counterparties fail to perform their obligations, we may suffer financial loss or be prevented from realizing the benefits of favorable price changes in the physical market.
The result of natural gas market prices exceeding our swap prices or collar ceilings requires us to make payment for the settlement of our hedge derivatives, if owed by us, generally up to three business days before we receive market price cash payments from our customers. This could have a material adverse effect on our cash flows for the period between hedge settlement and payment for revenues earned.
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The following table summarizes current hedging positions as of December 31, 2013:
| Oil collars: | Volumes (Bbls) | Floor Price | Ceiling Price | ||||||||
| 2014 | 80,444 | $ | 80.00 | $ | 103.50 | ||||||
| 2015 | 42,649 | $ | 80.00 | $ | 93.25 | ||||||
| Natural gas collars: | Volumes (MMBtu) | Floor Price | Ceiling Price | ||||||||
| 2014 | 1,528,083 | $ | 4.00 | $ | 4.41 | ||||||
| 2015 | 1,364,382 | $ | 4.00 | $ | — | ||||||
| Oil put options: | Volumes (Bbls) | Floor Price | |||||||||
| 2014 | 24,547 | $ | 80.00 | ||||||||
| Natural gas put options: | Volumes (MMBtu) | Floor Price | |||||||||
| 2014 | 445,768 | $ | 3.50 | ||||||||
| 2015 | 798,853 | $ | 3.50 | ||||||||
| 2016 | 930,468 | $ | 3.50 | ||||||||
| Natural gas liquids put options: | Volumes (Bbls) | Average Floor Price | |||||||||
| 2014 | 59,423 | $ | 28.66 | ||||||||
| Oil swaps: | Volumes (Bbls) | Fixed Price per Bbl | |||||||||
| 2014 | 14,634 | $ | 90.20 | ||||||||
| 2015 | 39,411 | $ | 88.90 | ||||||||
| 2016 | 36,658 | $ | 86.00 | ||||||||
| Natural gas swaps: | Volumes (MMBtu) | Average Price per MMBtu | |||||||||
| 2014 | 1,102,183 | $ | 4.09 | ||||||||
| 2015 | 800,573 | $ | 4.25 | ||||||||
| 2016 | 629,301 | $ | 4.37 | ||||||||
| Natural gas liquid swaps: | Volumes (MMBtu) | Average Price | |||||||||
| 2014 | 643,779 | $ | 39.79 | ||||||||
| 2015 | 84,793 | $ | 82.74 | ||||||||
Interest Rate Risk
Our primary exposure to interest rate risk results from outstanding borrowings under our revolving credit facility, which has a floating interest rate, and long-term debt held by our oilfield services segment. As of December 31, 2013, we had debt outstanding of $80.7 million with a weighted average interest rate of 3.25% on the Partnership's revolving credit facility and 6.27% on the oilfield services segment debt of $2.2 million and expenses on the unused borrowing base of 0.50%. Assuming no
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change in the amount outstanding, the annual impact on interest expense of a 10% increase or decrease in the average interest rate would be approximately $0.3 million.
Counterparty and Customer Credit Risk
We will monitor our risk of loss due to non-performance by counterparties of their contractual obligations. We have exposure to financial institutions in the form of derivative transactions in connection with our hedging activity. The counterparty on our derivative contracts currently in place is a lender under our revolving credit facility, with an investment grade rating and we are likely to enter into any future derivative contracts with this or other lenders under our revolving credit facility that also carry investment grade ratings. If one of these counterparties were to default on any of our derivative instruments while there is an outstanding balance under our revolving credit facility, we believe we would have the ability to offset the amount of any payment owing from this counterparty against the portion of the outstanding balance under our revolving credit facility then owed to such counterparty. We expect that any future derivative transactions we enter into will be with lenders under our revolving credit facility that carry an investment grade credit rating.
We also have exposure to credit risk through our operating partners and their management of the sale of our oil and natural gas production, which they market to energy marketing companies and refineries. We anticipate that we will monitor our exposure to these counterparties primarily by reviewing credit ratings, financial statements, production, sales, marketing, engineering and reserve reports. See “Item 1 - Business - Principal Customers” for further detail about our significant customers.
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| New Source Energy Partners L.P. | |
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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, 2013 and 2012, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2013. 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, 2013 and December 31, 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America.
/s/ BDO USA, LLP
Austin, Texas
April 4, 2014
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New Source Energy Partners L.P.
Consolidated Balance Sheets
(in thousands, except unit amounts)
| As of December 31, | |||||||
| 2013 | 2012 | ||||||
| ASSETS: | |||||||
| Current assets: | |||||||
| Cash | $ | 7,291 | $ | — | |||
| Accounts receivable | 12,609 | 5,663 | |||||
| Other current assets | 1,114 | 25 | |||||
| Total current assets | 21,014 | 5,688 | |||||
| Property and equipment, net | 8,166 | — | |||||
| Oil and natural gas properties, at cost, using full cost method: | |||||||
| Proved oil and natural gas properties | 291,829 | 202,795 | |||||
| Accumulated depreciation, depletion, and amortization | (128,961 | ) | (112,372 | ) | |||
| Total oil and natural gas properties, net | 162,868 | 90,423 | |||||
| Prepaid drilling and completion costs | 1,455 | 1,000 | |||||
| Intangible asset - customer relationships, net | 35,009 | — | |||||
| Goodwill | 23,974 | — | |||||
| Other assets | 2,224 | 2,823 | |||||
| Total assets | $ | 254,710 | $ | 99,934 | |||
| LIABILITIES, PARENT NET INVESTMENT AND PARTNERS' CAPITAL: | |||||||
| Current liabilities: | |||||||
| Accounts payable | $ | 2,268 | $ | — | |||
| Accounts payable—related parties | 8,221 | 1,564 | |||||
| Accrued liabilities | 999 | 259 | |||||
| Factoring payable | 1,907 | — | |||||
| Accrued income taxes | — | 103 | |||||
| Current derivative obligations | 3,167 | 47 | |||||
| Current portion of long-term debt | 719 | — | |||||
| Total current liabilities | 17,281 | 1,973 | |||||
| Contingent consideration payable to related parties | 6,320 | — | |||||
| Other long-term related party payables | 350 | 345 | |||||
| Credit facility | 78,500 | 68,000 | |||||
| Long-term debt, net of current portion | 1,514 | — | |||||
| Derivative obligations | 37 | 107 | |||||
| Asset retirement obligations | 3,455 | 1,510 | |||||
| Deferred tax liability | — | 12,024 | |||||
| Total liabilities | 107,457 | 83,959 | |||||
| Commitments and contingencies (See Note 16) | |||||||
| Parent net investment | — | 15,975 | |||||
| Partners' capital: | |||||||
| Common units (9,599,578 units issued and outstanding as of December 31, 2013) | 151,773 | — | |||||
| Subordinated units (2,205,000 units issued and outstanding as of December 31, 2013) | (17,334 | ) | — | ||||
| General partner units (155,102 units issued and outstanding as of December 31, 2013) | (1,174 | ) | — | ||||
| Total New Source Energy Partner L.P. partners' capital | 133,265 | — | |||||
| Non-controlling interests in subsidiary | 13,988 | — | |||||
| Total partners' capital | 147,253 | — | |||||
| Total liabilities, parent net investment and partners' capital | $ | 254,710 | $ | 99,934 | |||
The accompanying notes are an integral part of these financial statements.
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New Source Energy Partners L.P.
Consolidated Statements of Operations
(in thousands, except per unit amounts)
| Year Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| REVENUES: | |||||||||||
| Oil sales | $ | 8,090 | $ | 5,570 | $ | 4,489 | |||||
| Natural gas sales | 10,000 | 6,030 | 8,713 | ||||||||
| Natural gas liquids sales | 28,847 | 23,996 | 33,058 | ||||||||
| Service and rentals | 3,738 | — | — | ||||||||
| Total revenues | 50,675 | 35,596 | 46,260 | ||||||||
| OPERATING COSTS AND EXPENSES: | |||||||||||
| Oil and natural gas production expenses | 12,631 | 6,217 | 7,875 | ||||||||
| Oil and natural gas production taxes | 2,669 | 1,144 | 2,155 | ||||||||
| Cost of providing service and rentals | 2,040 | — | — | ||||||||
| General and administrative | 14,760 | 12,660 | 6,928 | ||||||||
| Depreciation, depletion, and amortization | 18,556 | 14,409 | 14,738 | ||||||||
| Accretion expense | 209 | 116 | 55 | ||||||||
| Total operating costs and expenses | 50,865 | 34,546 | 31,751 | ||||||||
| Operating (loss) income | (190 | ) | 1,050 | 14,509 | |||||||
| OTHER INCOME (EXPENSE): | |||||||||||
| Interest expense | (4,078 | ) | (3,202 | ) | (3,735 | ) | |||||
| Net gain (loss) on commodity derivatives (Note 11) | (5,548 | ) | 7,057 | (1,349 | ) | ||||||
| Gain on investment in acquired business | 22,709 | — | — | ||||||||
| Other income | 1,603 | — | — | ||||||||
| Income before income taxes | 14,496 | 4,905 | 9,425 | ||||||||
| Income tax benefit (expense) | 12,126 | (1,796 | ) | (10,502 | ) | ||||||
| Net income (loss) | $ | 26,622 | $ | 3,109 | $ | (1,077 | ) | ||||
| Net income | $ | 26,622 | |||||||||
| Net income prior to purchase of properties from New Source Energy on February 13, 2013 | $ | 5,303 | |||||||||
| Net income subsequent to purchase of properties from New Source Energy on February 13, 2013 | $ | 21,319 | |||||||||
| Net income allocable to general partner from February 13, 2013 to December 31, 2013 | $ | 291 | |||||||||
| Net income allocable to subordinated units from February 13, 2013 to December 31, 2013 | $ | 4,099 | |||||||||
| Net income allocable to common units from February 13, 2013 to December 31, 2013 | $ | 16,929 | |||||||||
| Net income per common unit for the period February 13, 2013 to December 31, 2013 | $ | 2.42 | |||||||||
The accompanying notes are an integral part of these financial statements.
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New Source Energy Partners L.P.
Consolidated Statements of Partners' Capital
(in thousands, except units)
| Partners' Capital | |||||||||||||||||||||||||||||||||
| Common Units | Subordinated Units | General Partner Units | Total New Source Energy Partners L.P. Partners' Capital | Non-Controlling Interests in Subsidiary | Total Partners' Capital | ||||||||||||||||||||||||||||
| Parent Net Investment | Units | Capital | Units | Capital | Units | Capital | |||||||||||||||||||||||||||
| Balance, December 31, 2010 | $ | 27,574 | — | $ | — | — | $ | — | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
| Net loss | (1,077 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| Equity-based compensation | 4,470 | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| Distribution to parent | (12,547 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| 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 from January 1, 2013 to February 12, 2013 | 5,303 | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| Allocated equity-based compensation of parent | 388 | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||
| Distribution to parent attributable to period from January 1, 2013 to February 12, 2013 | (2,495 | ) | — | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| Subordinated note 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 New Source in exchange for units | 26,901 | 777,500 | (7,306 | ) | 2,205,000 | (18,347 | ) | 150,000 | (1,248 | ) | (26,901 | ) | — | (26,901 | ) | ||||||||||||||||||
| Issuance of common units in initial public offering, net of offering costs | — | 4,250,000 | 76,565 | — | — | — | — | 76,565 | — | 76,565 | |||||||||||||||||||||||
| Issuance to general partner from overallotment exercised | — | — | — | — | — | 5,102 | — | — | — | — | |||||||||||||||||||||||
| Equity-based compensation | — | 367,500 | 7,350 | — | — | — | — | 7,350 | — | 7,350 | |||||||||||||||||||||||
| Purchases of oil and natural gas properties in exchange for units | — | 1,792,545 | 36,406 | — | — | — | — | 36,406 | — | 36,406 | |||||||||||||||||||||||
| Cash distributions | — | — | (9,477 | ) | — | (3,086 | ) | (217 | ) | (12,780 | ) | — | (12,780 | ) | |||||||||||||||||||
| Acquisition of MCE | — | 1,947,033 | 21,372 | — | — | — | — | 21,372 | 13,988 | 35,360 | |||||||||||||||||||||||
| Issuance of common units in private placement, net of offering costs | — | 465,000 | 9,833 | — | — | — | — | 9,833 | — | 9,833 | |||||||||||||||||||||||
| Unit compensation funded by unitholders | — | — | 101 | — | — | — | — | 101 | — | 101 | |||||||||||||||||||||||
| Net income attributable to the period from February 13, 2013 to December 31, 2013 | — | — | 16,929 | — | 4,099 | — | 291 | 21,319 | — | 21,319 | |||||||||||||||||||||||
| Balance, December 31, 2013 | $ | — | 9,599,578 | $ | 151,773 | 2,205,000 | $ | (17,334 | ) | 155,102 | $ | (1,174 | ) | $ | 133,265 | $ | 13,988 | $ | 147,253 | ||||||||||||||
The accompanying notes are an integral part of these financial statements.
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New Source Energy Partners L.P.
Consolidated Statements of Cash Flows
(in thousands)
| Years Ended December 31, | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||
| Net income (loss) | $ | 26,622 | $ | 3,109 | $ | (1,077 | ) | ||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||
| Depreciation, depletion, and amortization | 18,556 | 14,409 | 14,738 | ||||||||
| Gain on investment in acquired business | (22,709 | ) | — | — | |||||||
| Equity-based compensation | 7,839 | 8,204 | 4,470 | ||||||||
| Write-off of loan fees due to debt refinancing | 1,436 | — | 771 | ||||||||
| Change in fair value of contingent consideration | (1,600 | ) | — | — | |||||||
| Amortization of loan fees | 479 | 603 | 501 | ||||||||
| Accretion expense | 209 | 116 | 55 | ||||||||
| Deferred income tax expense (benefit) | (12,024 | ) | 1,694 | 10,330 | |||||||
| Unrealized (gain) loss on derivatives | 3,619 | (1,070 | ) | (150 | ) | ||||||
| Payments for derivative option premiums | (1,334 | ) | — | — | |||||||
| Changes in operating assets and liabilities, net of business acquired: | |||||||||||
| Accounts receivable | (10,595 | ) | 881 | (421 | ) | ||||||
| Other assets | 333 | — | — | ||||||||
| Accounts payable | 7,355 | (124 | ) | 531 | |||||||
| Accrued liabilities | 281 | 46 | 213 | ||||||||
| Accrued income taxes | (103 | ) | (69 | ) | 172 | ||||||
| Net cash provided by operating activities | 18,364 | 27,799 | 30,133 | ||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||
| Acquisition of oilfield services segment, net of MCE cash on hand | (2,259 | ) | — | — | |||||||
| Acquisition of oil and natural gas properties | (19,843 | ) | — | — | |||||||
| Additions to oil and natural gas properties and equipment | (28,921 | ) | (12,162 | ) | (23,818 | ) | |||||
| Net cash used in investing activities | (51,023 | ) | (12,162 | ) | (23,818 | ) | |||||
| CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||
| Proceeds from issuance of common units in initial public offering, net of deferred offering costs | 77,880 | — | — | ||||||||
| Proceeds from issuance of common units in private placement, net of offering costs | 9,833 | — | — | ||||||||
| Proceeds from borrowings on credit facility | 78,500 | 3,000 | 68,500 | ||||||||
| Proceeds from borrowings on credit facility (pre IPO) | 2,000 | — | — | ||||||||
| Payments on credit facility on credit facility (pre IPO) | (70,000 | ) | (3,500 | ) | (60,000 | ) | |||||
| Payment on subordinated note payable to parent | (25,000 | ) | |||||||||
| Proceeds from factoring payable | 229 | — | — | ||||||||
| Payment on MCE long-term debt | (102 | ) | — | — | |||||||
| Distributions to unitholders | (12,780 | ) | — | — | |||||||
| Payments for deferred loan costs | (1,954 | ) | (64 | ) | (2,268 | ) | |||||
| Distribution to parent | (18,295 | ) | (13,758 | ) | (12,547 | ) | |||||
| Abandoned offerings costs | (361 | ) | — | — | |||||||
| Payments for offering costs | — | (1,315 | ) | — | |||||||
| Net cash provided by (used in) financing activities | 39,950 | (15,637 | ) | (6,315 | ) | ||||||
| Net change in cash and cash equivalents | 7,291 | — | — | ||||||||
| Cash and cash equivalents at beginning of period | — | — | — | ||||||||
| Cash and cash equivalents at end of period | $ | 7,291 | $ | — | $ | — | |||||
| SUPPLEMENTAL CASH FLOW INFORMATION: | |||||||||||
| Cash paid for interest expense | $ | 2,061 | $ | 2,553 | $ | 2,250 | |||||
| NON-CASH INVESTING AND FINANCING ACTIVITIES: | |||||||||||
| Capitalized asset retirement obligation | $ | 1,735 | $ | (17 | ) | $ | 499 | ||||
| Change in accrued capital expenditures | 3,030 | (780 | ) | (1,160 | ) | ||||||
| Income taxes assumed by parent | — | 172 | — | ||||||||
| Accounts receivable distributed to parent | (7,014 | ) | — | — | |||||||
| Accounts payable assumed by parent | (1,742 | ) | — | — | |||||||
| Purchase of oil and natural gas properties in exchange for units | (36,406 | ) | — | — | |||||||
| Subordinated note given to parent in exchange for oil and gas properties | 25,000 | — | — | ||||||||
| Acquisition of MCE in exchange for units | (21,372 | ) | — | — | |||||||
The accompanying notes are an integral part of these financial statements.
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New Source Energy Partners L.P.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
Organization
New Source Energy Partners L.P. (the “Partnership” or “NSLP”) is a Delaware limited partnership formed in October 2012 by New Source Energy Corporation (“New Source”) to own and acquire oil and natural gas properties in the United States in addition to converting the Partnership from a pure play exploration and production company to a more fully integrated oil and gas partnership that over time can provide more services and infrastructure to enhance safety and efficiencies in developing and producing natural resources. The Partnership is engaged in the development and production of its oil and natural gas properties portfolio that extends across conventional resource reservoirs in east-central Oklahoma ("Exploration and Production Segment"). In addition, the Partnership is engaged in oilfield services that specialize in increasing efficiencies and safety in drilling and completion processes ("Oilfield Services Segment") through its wholly owned subsidiary, MidCentral Energy Services, LLC ("MCE" or "MCE Entities"), which, on November 12, 2013, it acquired through the acquisition 100% of the equity interests in MCE, LP, a Delaware limited partnership, and its general partner, MCE GP, LLC, other than Class B units in MCE, LP that were retained by certain of the sellers. See Note 15 for further discussion regarding the Partnership’s reportable segments.
On February 13, 2013, the Partnership completed its initial public offering (the “Offering”) of 4,000,000 common units representing limited partner interests in the Partnership at a price to the public of $20.00 per common unit. The Partnership received net proceeds of approximately $71.9 million from the Offering, after deducting underwriting discounts. The Partnership made a cash distribution of $15.8 million to New Source as consideration (together with its issuance to New Source 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 New Source of certain oil and gas natural properties (the “IPO Properties”) and certain commodity derivative contracts. Additionally, the Partnership assumed approximately $70.0 million of New Source's indebtedness previously secured by the IPO Properties, and used a portion of the net proceeds from the Offering to repay in full such assumed debt at the closing of the Offering. The Partnership also borrowed $15.0 million under a new revolving credit facility on February 13, 2013. On March 12, 2013, the Partnership received net proceeds of $4.7 million from the partial exercise, in the amount of 250,000 common units, of the underwriters’ overallotment option.
The IPO Properties consist of interests in wells producing oil, natural gas and NGLs from the Misener-Hunton (the “Hunton”) formation in East-Central Oklahoma. The IPO Properties represent New Source’s working interest in certain Hunton formation producing wells located in Pottawatomie, Seminole and Okfuskee Counties, Oklahoma (the “Golden Lane Area”), which equates to approximately a 38% weighted average working interest in the Golden Lane Area.
MCE is a limited liability company formed in June 2010 and is headquartered in and operates from Oklahoma City, Oklahoma. MCE offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region and has recently opened an additional field office in South Texas to focus on the Eagle Ford shale and in West Texas to focus on the Permian Basin. In addition, MCE offers short-term rentals out of Oklahoma City, Oklahoma of American Petroleum Institute (API) Certified irons such as: spacer spools; double-studded adapters; blowout preventers; ram blocks; choke manifolds; accumulators; and various other pressure components.
Basis of Presentation
The accompanying consolidated financial statements are prepared on a consolidated basis and present the financial position of the Partnership at December 31, 2013 and December 31, 2012 and the Partnership’s results of operations, partners' capital, and cash flows for the years ended December 31, 2013, 2012 and 2011. These consolidated financial statements include all adjustments, consisting of normal and recurring adjustments, which, in the opinion of management, are necessary for a fair presentation of the financial position and the results of operations for the indicated periods in accordance with accounting principles generally accepted in the United States of America, or “GAAP,” for financial reporting. All intercompany transactions are eliminated during the consolidation process. These consolidated financial statements include all accounts of the Partnership and those related to the "Non-Controlling Interest" owner (See "Note 12 - Unitholders' Equity").
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
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basis. As such, for periods prior to the Offering, the accompanying financial statements have been prepared on a "carve-out" basis from New Source's financial statements and reflect the historical accounts directly attributable to the IPO Properties together with allocations of expenses from New Source. 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, New Source performed certain corporate functions on behalf of the IPO Properties, and the consolidated financial statements reflect an allocation of the costs New Source incurred. These functions included executive management, information technology, tax, insurance, accounting, legal and treasury services. The costs of such services were allocated based on the most relevant allocation method to the service provided, primarily based on 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.
New Source 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. New Source was a taxable entity. Accordingly, on August 12, 2011, New Source 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 will not be a taxable entity. Accordingly, when New Source 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.
As part of the MCE Acquisition on November 12, 2103, certain owners of MCE retained Class B Units in MCE ("Class B Units"), which entitle the holders to receive incentive distributions of cash distributed by MCE above specified thresholds. Distributions to the Class B Units will be recognized in the period earned and recorded as a reduction to net income attributable to New Source Energy Partners L.P. on the Consolidated Statements of Operations.
Use of Estimates in the Preparation of the Consolidated Financial Statements
Preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves. Other significant estimates include, but are not limited to: the valuation of commodity derivatives; the allocation of general and administrative expenses; asset retirement obligations; goodwill/intangible impairment analysis; valuation of the consideration transferred for the MCE Acquisition; and the valuation of assets acquired and liabilities assumed in business combinations.
Acquisitions
The Partnership accounts for acquired businesses using the acquisition method of accounting, which requires that the assets acquired, liabilities assumed, contractual contingencies and contingent consideration be recorded at the date of acquisition at their respective fair values. Goodwill represents the excess of the purchase price, including any contingent consideration, over the fair value of the identifiable net assets acquired. It further requires acquisition related costs to be recognized separately from the acquisition and expensed as incurred.
The fair value of identifiable long-lived assets is based on significant judgments made by management of the Partnership. The Partnership typically engages third party valuation appraisal firms to assist in determining the fair values and useful lives of the identifiable long-lived assets acquired in the Oilfield Services Segment. Such valuations and useful life determinations require the Partnership to make significant estimates and assumptions. These estimates and assumptions are based on historical experience and information obtained from management, and also include, but are not limited to, future expected cash flows and discount rates applied in determining the present value of those cash flows. Unanticipated events and circumstances may occur that could affect the accuracy or validity of such assumptions, estimates or actual results. Acquired identifiable intangible assets are amortized on a pattern that is consistent with the net cash flows they are expected to produce over their estimated economic lives.
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Accounts Receivable
Accounts receivable consist of the following as of December 31, (in thousands):
| 2013 | 2012 | ||||||
| Oil and natural gas sales receivables | $ | 8,417 | $ | 5,621 | |||
| Oil and natural gas sales receivables - related parties | 228 | 42 | |||||
| Oilfield services receivables | 3,964 | — | |||||
| Total accounts receivable | $ | 12,609 | $ | 5,663 | |||
Accounts receivable are customer obligations due under normal trade terms and are presented on the Consolidated Balance Sheets net of allowances for doubtful accounts. Customers are granted credit in the ordinary course of business and generally do not require collateral. Based on management’s best estimate of the amount of probable credit losses in the Partnership's existing accounts receivable, it has concluded that realization of losses on balances outstanding at December 31, 2013 and 2012 will be immaterial; therefore, no allowance for doubtful accounts is deemed necessary. However, actual write-offs may occur. As part of the factoring payable mentioned below, certain of MCE's accounts receivable are pledged as collateral.
Property and Equipment
Property and equipment are capitalized and recorded at cost, while maintenance and repairs are expensed. Depreciation of property and equipment is provided when assets are placed in service using the straight-line method based on estimated useful lives ranging from three to ten years. Depreciation expense for property and equipment was $0.2 million for the year ended December 31, 2013. The Partnership did not incur any depreciation expense for property and equipment for the years ended December 31, 2012 and 2011.
Oil and Natural Gas Properties
The Partnership utilizes the full cost method of accounting for oil and natural gas properties whereby productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. All capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, are amortized to depreciation, depletion and amortization ("DD&A") expense using the units-of-production method based on total proved reserves. Historically, full cost pool amortization was recorded on a carve-out basis based on relative production from the Partnership compared to total production of New Source. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves. Under the full cost method, the net book value of oil and natural gas properties may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the ceiling limitation). In arriving at estimated after-tax future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. Reserve estimates used in determining estimated future net revenues have been prepared by an external petroleum engineering firm. Future net revenues were computed based on reserves using prices calculated as the unweighted arithmetical average oil and natural gas prices on the first day of each month within the latest twelve-month period. Subsequent to February 13, 2013, the ceiling limitation computation is determined without regard to income taxes due to the Partnership being a non-income tax paying entity. There were no full cost ceiling write-downs recorded for the years ended December 31, 2013, 2012 and 2011.
Intangible Asset - Customer Relationships
As part of the MCE Acquisition on November 12, 2013, $36.8 million of customer relationships intangible assets were recognized as part of the purchase price allocation (see Note 2). 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 7 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):
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| Total | ||||
| 2014 | $ | 12,366 | ||
| 2015 | 8,689 | |||
| 2016 | 5,264 | |||
| 2017 | 3,425 | |||
| 2018 | 1,839 | |||
| Thereafter | 3,426 | |||
| $ | 35,009 | |||
Amortization expense was $1.8 million for the year ended December 31, 2013. The Partnership did not incur any amortization expense for customer relationships for the years ended December 31, 2012 and 2011.
The Partnership evaluates for potential impairment of long-lived assets, including intangible assets, subject to amortization when indicators of impairment are present. Circumstances that could indicate a potential impairment include losses of significant customers, significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends, including oil and natural gas market prices could indicate a potential impairment. In performing an impairment evaluation, the Partnership estimates the future undiscounted net cash flows from the use and eventual disposition of the intangible asset grouped at the lowest level that cash flows can be identified. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount, an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management judgment. The Partnership did not record any impairment of long-lived assets for the years ended December 31, 2013, 2012 or 2011.
Goodwill
Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. In connection with the acquisition of MCE on November 12, 2013 (see Note 2), the Partnership recorded $24.0 million of goodwill, which represents the goodwill balance at December 31, 2013. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of November 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered.
In evaluating possible impairment of goodwill, the Partnership performs a qualitative assessment to determine whether it is more likely than not that the fair value of the reporting unit is impaired. Management uses all available information to make these determinations, including evaluating the macroeconomic environment, industry specific conditions, cost factors, overall financial performance and unit price, at the assessment date. The Partnership did not record any impairment of goodwill for the years ended December 31, 2013, 2012 or 2011.
Contingent Consideration Payable to Related Parties
Contingent consideration, which includes earnout payments in connection with the Partnership’s acquisitions, is recognized at fair value on the acquisition date and remeasured each reporting period with subsequent adjustments recognized in our 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 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. At each reporting date, the contingent consideration liability is revalued to estimated fair value.
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 earnout criteria. These changes could cause a material impact to, and volatility in our operating results. Earnout 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 our Consolidated Statements of Cash Flows. See Note 10 for contingent consideration activity.
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Environmental
Oil and natural gas properties are subject to extensive federal, state and local environmental laws and regulations. These laws, which are often changing, regulate the discharge of materials into the environment and may require the removal or mitigation of the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable.
Revenue Recognition
Oil and natural gas sales are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred, and collectability of the revenue is probable. Delivery occurs and title is transferred when production has been delivered to a pipeline, railcar or truck, or a tanker lifting has occurred. The sales method of accounting is used for oil and natural gas sales such that revenues are recognized based on the actual proceeds from the oil and natural gas sold to purchasers. Oil and natural gas imbalances are generated on properties for which two or more owners have the right to take production “in-kind” and, in doing so, take more or less than their respective entitled percentage. For the years ended December 31, 2013, 2012 and 2011 there were no significant oil and natural gas imbalances.
The Oilfield Services Segment's service and rental revenue is recognized when persuasive evidence of an arrangement exists, the product or service has been provided, the price is fixed or determinable and collection is reasonably assured, which is generally at the time the service is provided.
Asset Retirement Obligations
Liabilities associated with asset retirement obligations are recorded at fair value in the period in which they are incurred or when properties are acquired with a corresponding increase in the carrying amount of the related oil and natural gas properties. Subsequently, the asset retirement cost included in the carrying amount of the oil and natural gas properties and is allocated to expense through DD&A. Changes in the liability due to passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.
Equity-Based Compensation
Awards under the Partnership’s long-term incentive plan may consist of restricted stock grants, equity option awards, and other awards issuable to employees and non-employee directors. The Partnership recognizes in its consolidated financial statements the cost of employee services received in exchange for awards of equity instruments based on the fair value of those awards at their grant date. If an award has a fixed vesting date, the cost is recognized over the period from the grant date to the vesting date(s) of the award. If an award does not have a fixed vesting date, the cost is recognized at the time it vests.
Income Taxes
Income taxes are reflected in these 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.
The Company is 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 Company are passed through to its unitholders. Limited partnerships are subject to Texas margin tax.
In accordance with the applicable accounting standards, the Partnership recognizes only the impact of income tax positions that, based on their merits, are more likely than not to be sustained upon audit by a taxing authority. To evaluate its current tax positions in order to identify any material uncertain tax positions, the Partnership developed a policy of identifying and evaluating uncertain tax positions that considers support for each tax position, industry standards, tax return disclosures and schedules and the significance of each position. It is the Partnership’s policy to recognize interest and penalties, if any, related to unrecognized tax benefits in income tax expense. The Partnership had no material uncertain tax positions at December 31, 2013, and December 31, 2012. The tax years 2010 – 2012 remain open to examination for federal income tax purposes.
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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 $118.9 million at December 31, 2013.
Fair Value of Financial Instruments
The fair value of a financial instrument is the amount at which the instrument could be exchanged in an orderly transaction between two willing parties. The carrying amount of cash, accounts receivable, prepaid expenses, accounts payable, accrued expenses reported on the balance sheet approximates fair value. The carrying amount of the borrowings under the credit facility and our other borrowings reported on the balance sheets approximates fair value (level 2) because the debt instruments carry a variable interest rate based on market interest rates.
Derivatives
All derivative instruments are recognized as either assets or liabilities in the balance sheet at fair value. None of such instruments have been designated as cash flow hedges. Accordingly, changes in the fair value of all derivative instruments have been recorded in the consolidated statements of operations.
2. Acquisitions
The Partnership completed six acquisitions during 2013. Five of those acquisitions broaden the Partnership's growing portfolio of oil and natural gas properties. The acquisition of MCE contributes to the Partnership's long-term goals of converting the Partnership from a pure play Exploration and Production company to a more fully integrated oil and gas partnership that over time can provide more services and infrastructure to enhance safety and efficiencies in developing and producing natural resources. All acquisitions in 2013 were of a related party nature with exception of the "Orion Acquisition." Each of the acquisitions were accounted for under FASB ASC 805, "Business Combinations."
March Acquired Properties
On March 29, 2013, we completed an acquisition with an effective date of March 1, 2013, of certain oil and natural gas properties located in Oklahoma (the “March Acquired Properties”) from New Source, Scintilla, and W.K. Chernicky, LLC, an Oklahoma limited liability company for an aggregate adjusted price of $28.0 million. As consideration for the properties, the Partnership issued an aggregate of 1,378,500 common units valued at $20.30 per unit. The properties are located in the Golden Lane field, where the Partnership's existing properties are located, and in the Luther field, which is adjacent to the Golden Lane field.
This transaction was unanimously approved by the board of directors of the Partnership's general partner, based on the approval and recommendation of its conflicts committee. The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition as follows (in thousands):
| March 29, 2013 | |||
| Proved oil and natural gas properties | $ | 29,049 | |
| Other assets acquired | 754 | ||
| Fair value of assets acquired | 29,804 | ||
| Asset retirement obligations | (1,333 | ) | |
| Other liabilities assumed | (488 | ) | |
| Fair value of net assets acquired | $ | 27,984 | |
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May Acquired Properties
On May 31, 2013, the Partnership completed an acquisition of certain oil and natural gas properties located in Oklahoma (the “May Acquired Properties”) from New Source, with an effective date of May 1, 2013. As consideration for the May Acquired Properties, the Partnership paid a total of $8.1 million in cash to New Source. After purchase price adjustments, the total consideration was $7.9 million.
This transaction was unanimously approved by the board of directors of the Partnership's general partner, based on the approval and recommendation of its conflicts committee. The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition as follows (in thousands):
| May 31, 2013 | |||
| Proved oil and natural gas properties | $ | 8,165 | |
| Fair value of assets acquired | 8,165 | ||
| Asset retirement obligations | (19 | ) | |
| Other liabilities assumed | (254 | ) | |
| Fair value of net assets acquired | $ | 7,893 | |
July Scintilla Acquired Properties
On July 23, 2013, the Partnership completed an acquisition of a 10% working interest in certain oil and natural gas properties located in Oklahoma (the “July Scintilla Acquired Properties”) from Scintilla, with an effective date of May 1, 2013. As consideration for the July Scintilla Acquired Properties, the Partnership paid a total of $4.9 million in cash to Scintilla after purchase price adjustments.
This transaction was unanimously approved by the board of directors of the Partnership's general partner, based on the approval and recommendation of its conflicts committee. The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition as follows (in thousands):
| July 23, 2013 | |||
| Proved oil and natural gas properties | $ | 4,888 | |
| Fair value of assets acquired | 4,888 | ||
| Asset retirement obligations | (4 | ) | |
| Other liabilities assumed | (18 | ) | |
| Fair value of net assets acquired | $ | 4,866 | |
Orion Acquired Properties
On July 25, 2013 the Partnership acquired certain oil and natural gas properties from, located in Oklahoma (the "Orion Acquired Properties") from Orion Exploration Partners, LLC, with an effective date of May 1, 2013. The Partnership paid $3.2 million in cash for the Orion Acquired Properties after purchase price adjustments.
This transaction was unanimously approved by the board of directors of the Partnership's general partner. The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition as follows (in thousands):
| July 25, 2013 | |||
| Proved oil and natural gas properties | $ | 3,274 | |
| Fair value of assets acquired | 3,274 | ||
| Asset retirement obligations | (24 | ) | |
| Other liabilities assumed | (20 | ) | |
| Fair value of net assets acquired | $ | 3,230 | |
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Southern Dome Acquired Properties
On October 4, 2013, the Partnership completed an acquisition of working interests in 25 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma (the “Southern Dome Acquired Properties”) from Scintilla, with an effective date of August 1, 2013. As consideration for the working interests, the Partnership paid $5.0 million in cash to Scintilla at closing and issued 414,045 common units with a fair market value of $20.79 (closing price on the date of the transaction) or $8.6 million to Scintilla in November 2013. The Partnership also agreed to provide additional consideration to Scintilla in November 2014 if the production attributable to the working interests for the nine-month period ending September 30, 2014 exceeds the average daily production of 383.5 Boe/d ("Southern Dome Contingent Consideration"), which had an estimated fair value of $1.6 million on the acquisition date and was considered part of the purchase price, for a total consideration of $14.5 million after purchase price adjustments. As detailed in the Contribution Agreement, the additional consideration was calculated as the acquisition value of the production increase (applying the same valuation methodology as was used to determine the initial consideration with respect to the Current Production Average) less (i) the 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 that were not producing in paying quantities as of the effective date of the acquisition. In addition, the fair value of the contingent consideration was based on the weighted probability of achievement of certain performance milestones. The Partnership may satisfy any such additional consideration in cash, common units, or a combination thereof at its discretion.
This transaction was unanimously approved by the board of directors of the Partnership's general partner, including each member of its conflicts committee. The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition as follows (in thousands):
| October 4, 2013 | |||
| Proved oil and natural gas properties | $ | 15,190 | |
| Fair value of assets acquired | 15,190 | ||
| Asset retirement obligations | (170 | ) | |
| Other liabilities assumed | (552 | ) | |
| Fair value of net assets acquired | $ | 14,469 | |
MCE Acquisition
On November 12, 2013, the Partnership acquired 100% of the equity interests in the MCE Entities, other than Class B Units that were retained by certain of the sellers and are described below. MCE operates an oilfield services business headquartered in Oklahoma City, Oklahoma. MCE offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region, along with the rental of certain ancillary equipment necessary to perform such services. In addition to its presence in the Mid-Continent region, MCE recently opened field offices in South Texas to focus on the Eagle Ford Shale and in West Texas to focus on the Permian Basin. The effective date of this acquisition was November 1, 2013.
The Partnership acquired the MCE Entities in exchange for $68.2 million in total consideration, which consisted of approximately $3.8 million in cash, 1,847,265 Partnership common units, valued at $22.64 (closing price on the date of the transaction) per common unit, issued to the MCE Owners in exchange for their equity interests in MCE, 99,768 Partnership common units, valued at $22.64 per common unit, issued to certain employees of MCE under the Partnership’s long-term incentive plan, $6.3 million in contingent consideration and $14.0 million in Class B Units in MCE. The Partnership recorded acquisition-related costs of $0.8 million in general and administrative expense for the year ended December 31, 2013. The acquisition was accounted for using the acquisition method of accounting.
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The Partnership used a third-party valuation specialist to assist in determining the fair value for the total consideration, the assets acquired and the liabilities assumed as of the acquisition date. The fair value of the total consideration was allocated to the fair value of the assets acquired, the liabilities assumed, non-controlling interests and the resulting goodwill. Accordingly, the consolidated financial statements include an allocation of the purchase price based on assumptions and estimates. A summary of the purchase price allocation made in connection with the MCE Acquisition is as follows (in thousands):
| November 12, 2013 | ||||
| Cash Paid | $ | 3,781 | ||
| Fair value of common units granted (1) | 41,822 | |||
| Common units granted to MCE employees (2) | 2,259 | |||
| Earn-out amount (contingent consideration) (3) | 6,320 | |||
| MCE Class B units granted (4) | 13,988 | |||
| Total fair value consideration transferred | $ | 68,170 | ||
| (1) | 1,847,265 common units valued at $22.64 per unit. |
| (2) | 99,768 common units valued at $22.64 per unit. These common units were issued to certain employees of MCE, under the Partnership’s long-term incentive plan. If the recipients of the common units do not remain employed by MCE for three years, then they forfeit the units. The common units do not revert to the Partnership, but would be distributed to the former owners of MCE. The $2.3 million fair value of the common units is included in the consideration transferred for the MCE Acquisition, as the units do not revert back to the Partnership upon any circumstance. Since this compensation arrangement is funded by unitholders, the compensation will be reflected in the accompanying Consolidated Statements of Operations over the three-year straight-line vesting period. See Note 14, Equity-Based Compensation, for more information. |
| (3) | The owners of MCE are entitled to receive additional Partnership common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $120 million cap ("MCE Contingent Consideration"). The MCE Contingent Consideration was valued at $6.3 million at the acquisition date and was considered as part of the purchase price of MCE. The Partnership determined the fair value of the MCE Contingent Consideration with the assistance of a third-party valuation specialist through the use of a Monte Carlo simulation, which allows for an open-form approach to allocate value. The simulation generates value based on probability distributions similar to those used under closed-form models. |
| (4) | Certain 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 12). The Class B units were valued at $14.0 million at the acquisition date and were considered as part of the purchase price of MCE. The Partnership determined the fair value of the Class B Units with the assistance of a third-party valuation specialist through the use of a Monte Carlo simulation, which allows for an open-form approach to allocate value. The simulation generates value based on probability distributions similar to those used under closed-form models. |
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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):
| November 12, 2013 | ||||
| Assets | ||||
| Cash | $ | 1,522 | ||
| Accounts receivable | 3,365 | |||
| Other current assets | 954 | |||
| Property and Equipment | 7,923 | |||
| Intangible asset - customer relationship | 36,772 | |||
| Goodwill | 23,974 | |||
| Other assets | 19 | |||
| Liabilities | ||||
| Accounts payable | (1,199 | ) | ||
| Accounts payable - related parties | (870 | ) | ||
| Accrued liabilities | (276 | ) | ||
| Factoring payable | (1,679 | ) | ||
| Current portion of long-term debt | (719 | ) | ||
| Long-term debt | (1,616 | ) | ||
| Net assets acquired | $ | 68,170 | ||
Since the MCE Acquisition was accounted for under FASB ASC 805, "Business Combinations." The fair values of the assets acquired and liabilities assumed were determined using the market, income, and cost approaches. The market approach, which indicates value for a subject asset based on available market pricing for comparable assets, was utilized to estimate the fair value of MCE property and equipment. The market approach used by the Company included prices and other relevant information generated by market transactions involving comparable assets. The income approach was primarily used to value customer relationships. The income approach indicates value for a subject asset based on the present value of future cash flows projected to be generated by the asset and applies the operating expenses required to support the forecasted revenue stream. Projected future cash flows are discounted at a required market rate of return that reflects the relative risk of achieving the cash flows and the time value of money. The cost approach, which estimates value by determining the current cost of replacing an asset with another of equivalent economic utility, was used, as appropriate, for certain assets for which the market and income approaches could not be applied due to the nature of the asset. The cost to replace a given asset reflects the estimated reproduction or replacement cost for the asset, less an allowance for loss in value due to depreciation.
Since the President and Chief Executive Officer of the Partnership's general partner, Kristian B. Kos ("Mr. Kos"), through his control over the Partnership’s general partner, controls the Partnership and Mr. Kos also owned 36% of the equity interest in MCE, the Partnership accounted for the acquisition as a business combination achieved in stages under FASB ASC 805-10. The Partnership initially recorded the 36% equity interest in MCE acquired from Mr. Kos at Mr. Kos’ equity method carrying basis, which was $1.8 million as of November 12, 2013, as this was a transaction between entities under common control. The Partnership remeasured the 36% interest acquired from Mr. Kos at its acquisition-date fair value and recognized a corresponding gain of $22.7 million, recorded as a gain on investment in acquired business in the accompanying Consolidated Statements of Operations for the year ended December 31, 2013. The acquisition of the remaining 64% of MCE was accounted for as a purchase at fair value.
Customer Relationships, an identifiable intangible asset was created as a result of the acquisition of MCE, which is being amortized by an accelerated amortization schedule to reflect the estimated free cash flows the customer relationships are expected to provide. See Note 1 for further information on intangible assets.
Goodwill in the amount of $24.0 million has been recorded for the acquisition of MCE. 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. None of the goodwill is deductible for tax purposes. Specifically, the goodwill recorded as part of the acquisition of MCE includes any intangible assets that do not qualify for separate recognition, such as the MCE trained, skilled and assembled workforce, along
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with the expected synergies from leveraging the customer relationships and integrating new product offerings into MCE's business.
Pro forma for information for material acquisitions (unaudited)
The acquisition of the March Acquired Properties, the Southern Dome Acquired Properties and the MCE Acquisition (collectively, the "Material Acquisitions") were deemed material for purposes of the following pro forma disclosures. The Material Acquisitions were not included in the Partnership's consolidated results until their closing dates. For the periods after the closing date of each Material Acquisition to December 31, 2013, the Material Acquisitions contributed revenue of $11.5 million and operating income of $6.5 million for the year ended December 31, 2013.
The operating income attributable to the Material Acquisitions does not reflect certain expenses, such as general and administrative and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. The financial information was derived from the Partnership's audited historical consolidated financial statements for the years ended December 31, 2013 and 2012, the Material Acquisitions' audited and historical financial statements for the year ended December 31, 2012 and the Material Acquisitions' unaudited interim financial statements from January 1, 2013 to each closing date. The following unaudited pro forma consolidated financial information has been prepared as if the Material Acquisitions occurred on January 1, 2012 for the years ending December 31, (in thousands, except per unit data).
| Pro forma | |||||||
| 2013 | 2012 | ||||||
| Revenue: | |||||||
| As reported | $ | 50,675 | $ | 35,596 | |||
| Pro forma | $ | 77,892 | $ | 67,599 | |||
| Net Income (loss): | |||||||
| As reported | $ | 26,622 | $ | 3,109 | |||
| Pro forma | $ | (3,438 | ) | $ | 12,420 | ||
| Basic net income (loss) per unit: | |||||||
| As reported | $ | 2.42 | |||||
| Pro forma | $ | (0.36 | ) | ||||
| Diluted net income (loss) per unit: | |||||||
| As reported | $ | 2.42 | |||||
| Pro forma | $ | (0.36 | ) | ||||
These pro-forma adjustments have been calculated after applying the Partnership's accounting policies and adjusting the results to reflect additional depreciation and amortization that would have been charged assuming the properties and intangible assets were acquired and fair value adjustments to property and equipment and intangible assets had been applied. In addition, pro forma adjustments have been made for the interest that would have been incurred for financing the acquisitions with the Partnership's credit facility, and pro forma net income per unit amounts assume the units issued in these acquisitions had been outstanding since January 1, 2012. In computing pro forma net income, the $22.7 million gain on Mr. Kos' equity method investment in the acquired business mentioned above has been removed from 2013 net income and reflected in 2012. These pro forma results of operations have been prepared for comparative purposes only and they do not purport to be indicative of the results of operations that actually would have resulted had the acquisitions occurred on the date indicated or that may result in the future.
CEU Acquired Properties
On January 31, 2014, the Partnership completed an 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 Acquired Properties”). See Note 18, Subsequent Events regarding more details of this transaction.
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3. Related Parties
Using ownership information as of December 31, 2013, the Partnership is controlled by the Partnership's general partner, which is owned 69.4% by Mr. Kos, and 25.0% by the Chairman and Senior Geologist of the Partnership, David J. Chernicky ("Mr. Chernicky"). Mr. Kos owns approximately 8.3% of the Partnership's outstanding common units, including units owned through the Partnership's long-term incentive plan, and units owned through Deylau, LLC, an entity he controls. Mr. Chernicky owns approximately 27.6% of the Partnership's outstanding common units, including units owned through the Partnership's long-term incentive plan, and units owned through New Source and Scintilla, entities which he controls. In addition, Mr. Chernicky owns 100% of the 2,205,000 subordinated units through New Source. Mr. Chernicky owns all of the membership interests in the entity that operates the Partnership's properties, New Dominion, LLC ("New Dominion").
New Dominion, LLC
New Dominion is an exploration and production operator based in Tulsa, Oklahoma and is wholly-owned by Mr. Chernicky. Pursuant to the Partnership’s development agreement, New Dominion is currently contracted to operate the Partnership’s existing wells. New Dominion has historically performed this service for New Source.
New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated is approximately $0.3 million as of December 31, 2013, all of which is classified as a long-term liability, and $0.6 million as of December 31, 2012, of which $0.3 million was classified as a short-term liability and $0.3 million was classified as a long-term liability. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.
The expenses incurred by the Partnership billed by New Dominion consist of the following:
•Producing overhead charges included in the Partnership properties’ oil and natural gas expenses.
| • | Drilling and completion overhead charges included in the Partnership properties’ full cost pool of oil and natural gas properties. |
| • | Saltwater disposal access fee charges included in the Partnership's capitalized oil and gas properties full cost pool and salt water disposal fees included in oil and natural gas production expenses. |
| • | Administrative fees included in general and administrative expenses. |
The expense amount incurred for these charges are as follows for the years ended December 31, (in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Access fee charges | $ | 250 | $ | 2,615 | $ | 196 | |||||
| Producing overhead charges | 980 | 599 | 581 | ||||||||
| Drilling and completion overhead charges | 101 | 27 | 26 | ||||||||
| Saltwater disposal fees | 696 | 1,642 | 1,612 | ||||||||
| Administrative fees | 9 | — | — | ||||||||
| Total expenses incurred | $ | 2,035 | $ | 4,883 | $ | 2,415 | |||||
New Source
On February 13, 2013, in connection with the closing of the Offering, the Partnership entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among New Source, the Partnership and our general partner. Pursuant to the Omnibus Agreement, New Source provided management and administrative services for the Partnership and our general partner for the year ended December 31, 2013. From the closing of the Offering through December 31, 2013, the Partnership paid New Source Energy a quarterly fee of $0.7 million for the provision of such services, totaling $2.4 million for the year ended December 31, 2013, which included a prorated fee of $0.4 million for the period from February 13, 2013 through March 31, 2013 in its
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general and administrative expenses. After December 31, 2013, in lieu of the quarterly fee, our general partner will reimburse New Source, on a quarterly basis, for the actual direct and indirect expenses it incurs in its performance under the Omnibus Agreement, and the Partnership will reimburse our general partner for such payments it makes to New Source. Prior to February 13, 2013, the Partnership’s consolidated financial statements reflected an allocated portion of the general and administrative expenses of the owner of the IPO Properties.
Oilfield Services Segment
Mr. Kos was a 36% owner of the MCE Entities prior to the MCE Acquisition.
Dikran Tourian, the President of the Oilfield Services Segment, was a 36% owner of the MCE Entities prior to the MCE Acquisition and was appointed to serve as a member of the board of directors of our general partner in February 2014.
The conflicts committee of the board of directors of our general partner, which consists of two independent directors, reviewed the MCE Acquisition and related terms and agreements, engaged and consulted with independent financial and legal advisors with respect thereto, and granted “special approval” under our partnership agreement with respect to the “MCE Contribution Agreement." Based on this approval and recommendation from the conflicts committee, our general partner’s board of directors approved the MCE Acquisition.
Transactions with Directors and Officers
New Source, through the Omnibus Agreement, engaged Finley & Cook, PLLC to provide various accounting services during the year ended December 31, 2013. Richard Finley, our Chief Financial Officer, is an equity member of Finley & Cook, holding a 31.5% ownership interest. New Source paid Finley & Cook approximately $0.5 million, $0.5 million and $0.1 million, in fees for accounting services for the years ended December 31, 2013, 2012 and 2011, respectively.
4. Property and equipment
Major classes of property and equipment included the following at December 31, (in thousands):
| Useful life | 2013 | ||||
| Light-duty trucks | 3 years | $ | 516 | ||
| Machinery and equipment | 3-10 years | 4,793 | |||
| Rental iron | 20 years | 2,971 | |||
| Other assets | 3-7 years | 88 | |||
| Less accumulated depreciation | (202 | ) | |||
| Total Property and equipment, net | $ | 8,166 | |||
Property and equipment only relates to our Oilfield Services Segment, which was acquired on November 12, 2013. Therefore, property and equipment is not presented as of December 31, 2012.
5. Asset Retirement Obligations
Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties at the end of their productive lives in accordance with applicable laws. There were no assets legally restricted for purposes of settling asset retirement obligations as of December 31, 2013 and 2012.
The following table summarizes activity associated with asset retirement obligations for the years ending December 31, (in thousands):
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| 2013 | 2012 | 2011 | |||||||||
| Asset retirement obligations, beginning of period | $ | 1,510 | $ | 1,411 | $ | 857 | |||||
| Liabilities incurred from acquisitions and new wells drilled | 1,585 | 34 | 499 | ||||||||
| Revision of previous estimates | 151 | (51 | ) | — | |||||||
| Accretion expense | 209 | 116 | 55 | ||||||||
| Asset retirement obligations, end of period | $ | 3,455 | $ | 1,510 | $ | 1,411 | |||||
6. Major Customers
The majority of the Partnership's oil and natural gas properties produce from the Hunton formation in east-central Oklahoma. The following table represents oil and natural gas sales by customer who purchased more than 10% of our production for the years ended December 31,:
| Purchaser | 2013 | 2012 | 2011 | |||
| Scissortail | 80% | 84% | 90% | |||
| United Petroleum Purchasing | 14% | 16% | <10% | |||
This market is served by multiple oil and natural gas purchasers. As a result, the Partnership believes the loss of any one purchaser would not have a material adverse effect on the ability of the Partnership to sell its oil and natural gas production.
7. Credit Facility and Factoring Payable
Credit Facility:
On February 13, 2013, in connection with the closing of the IPO, the Partnership entered into a Credit Agreement by and among the Partnership, as borrower, Bank of Montreal, as administrative agent for the lenders party thereto (the “Administrative Agent”), and the other lenders party thereto (the “Credit Agreement”).
The Credit Agreement is a four-year, senior secured revolving credit facility. The borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to the estimated oil and natural gas reserves of the Partnership, which will take into account the prevailing oil and gas prices at such time, as adjusted for the impact of commodity derivative contracts. The Credit Agreement is available for working capital for exploration and production and for general partnership purposes.
On February 28, 2013, the Partnership entered into a First Amendment (the “First Amendment”) to its Credit Agreement. The First Amendment (i) added a lender under the Credit Agreement, (ii) increased the Partnership’s borrowing base under the Credit Agreement from $30 million to $60 million, (iii) increased the lenders’ aggregate commitment under the Credit Agreement from $60 million to $150 million and (iv) removed references and provisions related to the $25 million subordinated promissory note (the “Subordinated Note”) issued by the Partnership to New Source in connection with the Partnership’s initial public offering. As a condition precedent to effectiveness of the First Amendment, the Partnership repaid the Subordinated Note in full.
On June 25, 2013, the Partnership entered into a Second Amendment (the “Second Amendment”) to its Credit Agreement. The Second Amendment (i) added two lenders under the Credit Agreement, and (ii) increased the Partnership’s borrowing base under the Credit Agreement from $60 million to $75 million.
On October 29, 2013, the Partnership entered into a Third Amendment (the “Third Amendment”) to its Credit Agreement. The Third Amendment (i) adds a lender under the Credit Agreement, and (ii) increases the Partnership’s borrowing base under the Credit Agreement from $75 million to $87.5 million.
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On November 12, 2013, the Partnership entered into a Fourth Amendment (the “Fourth Amendment”) to its Credit Agreement. The Fourth Amendment amends certain provisions of the Credit Agreement with respect to the MCE Acquisition. The Fourth Amendment, among other things, provides that (i) the MCE Entities are not a “Subsidiary” for the purposes of the Credit Agreement, (ii) the Partnership may include actual cash dividends paid by MCE to the Partnership in the Partnership’s calculation of financial covenants, (iii) the Partnership may use proceeds of the Credit Agreement to make permitted investments in the MCE Entities and (iv) future investments in the MCE Entities may be made (a) with proceeds of the sales of the Partnership’s common units or (b) in an amount not to exceed $5.0 million in any twelve month period (without regard to any investments made pursuant to clause (a)), in each case, subject to certain limitations.
The Credit Agreement requires NSLP to maintain 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, a ratio of total debt to EBITDA of not more than 3.5 to 1.0 and a ratio of consolidated current assets to consolidated current liabilities of not less than 1.0 to 1.0, in each case as more fully described in the Credit Agreement.
Additionally, the Credit Agreement contains various covenants and restrictive provisions that, among other things, limits the ability of 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 Agreement permits the Partnership to make distributions to its common unit holders in an amount not to exceed “Available Cash” (as defined in the Partnership's limited partnership agreement) so long as (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the Credit Agreement does not exceed 90%. At December 31, 2013, under the most restrictive terms of our covenants, partners’ capital of $7.5 million was available for distribution.
Events of default under the Credit Agreement include, but are not limited to, the failure to make payments when due, breach of any covenants continuing beyond the cure period.
Borrowings under the Credit Agreement bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus 0.5%, (b) the Administrative Agent’s prime rate or (c) LIBOR plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of 0.50% per annum. Accrued interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans, at shorter intervals and the variable rate was approximately 3.25% per annum at December 31, 2013. The Credit Agreement does not require principal repayments, unless the outstanding balance exceeds the borrowing base, and matures on February 13, 2017. As of December 31, 2013, the Partnership had $78.5 million outstanding under the Credit Agreement and, as a result, had $9.0 million of available borrowing capacity.
All of the partnership's oil and gas properties serve as collateral for borrowings under the credit agreement. The Partnership was in compliance with all covenants of the Credit Agreement as of December 31, 2013.
Credit Facility (Pre IPO):
As of December 31, 2012, the Partnership had approximately $68.0 million outstanding under its credit facility, which related to a $150.0 million four-year credit facility with the Bank of Montreal entered into in August, 2011 ("Credit Facility-Pre IPO"). The borrowing base was re-determined in August, 2012 and was reduced from $72.5 million to $70 million. The Credit Facility-Pre IPO was paid off in full with proceeds from the Offering in 2013.
Factoring Payable:
The Partnership is a party to a secured borrowing agreement to factor the accounts receivable of the Oilfield Services Segment. The Partnership receives 90% funding immediately, and 10% is held in a reserve account with the factoring company for each invoice that is factored. Customers remit payment directly to the factoring company. Based on the number of days until collection, there is a tiered interest schedule (rates increase each 15 day period up to a maximum of 5% or an annualized rate of 20%) that is charged against the Partnership’s reserve account. The remaining amount in the reserve account is then released to the Partnership on a weekly basis as collections occur. 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. Proceeds from the arrangement are reflected as borrowings in our financial statements.
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The outstanding balance was $1.9 million as of December 31, 2013. Fees of $39,888 were incurred for the period November 12, 2013 (date of acquisition) through December 31, 2013, and are included in interest expense. MCE paid all outstanding balances and terminated this agreement in February 2014.
8. Long-Term Debt
The Partnership has $2.2 million in debt as of December 31, 2013 related to financing notes with various lending institutions for certain property and equipment through its Oilfield Services Segment. These notes range from 36-48 months in duration with maturity dates from May 2016 through April 2018 and carry variable interest rates ranging from 5.75% to 10.29%. All notes are associated with specific capital assets of the MCE Entities and are secured by MCE assets.
The following is a schedule by years of minimum principal payments required under the Long-Term Debt and Credit Facility as of December 31, 2013 (in thousands):
| Year ended December 31, | Amount | |||
| 2014 | $ | 719 | ||
| 2015 | 766 | |||
| 2016 | 558 | |||
| 2017 (1) | 78,651 | |||
| 2018 | 39 | |||
| Total | $ | 80,733 | ||
(1) Includes Credit Facility borrowings of $78.5 million maturing in February, 2017.
9. Fair Value Measurements
Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. As defined in Financial Accounting Standards Board Accounting Standards Codification Topic (“ASC”) 820-10, fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Partnership considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Partnership values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as oil swaps.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). The Partnership’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments primarily include derivative instruments, such as NGLs swaps, natural gas swaps for those derivatives that are indexed to local and non-observable indices, and oil, NGL and natural gas collars. Although management utilizes third party broker quotes to assess the reasonableness of our prices and valuation techniques, management does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.
As required by ASC 820-10, financial assets and liabilities 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
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measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.
Fair Value on a Recurring Basis
The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis and recorded in other assets and derivative obligations in our Consolidated Balance Sheets as of December 31, 2013 and 2012 (in thousands):
| Active Markets for Identical Assets (Level 1) | Observable Inputs (Level 2) | Unobservable Inputs (Level 3) | Total Carrying Value | ||||||||||||
| Oil puts | $ | — | $ | 28 | $ | — | $ | 28 | |||||||
| Oil collars | — | (57 | ) | — | (57 | ) | |||||||||
| Natural gas collars | — | — | (9 | ) | (9 | ) | |||||||||
| Oil and natural gas swaps | — | 132 | — | 132 | |||||||||||
| Natural gas and NGL puts | — | — | 403 | 403 | |||||||||||
| NGL swaps | — | — | (2,911 | ) | (2,911 | ) | |||||||||
| Balance December 31, 2013 | $ | — | $ | 103 | $ | (2,517 | ) | $ | (2,414 | ) | |||||
| Oil and natural gas swaps | $ | — | $ | (17 | ) | $ | — | $ | (17 | ) | |||||
| NGL swaps | — | — | (112 | ) | (112 | ) | |||||||||
| Balance December 31, 2012 | $ | — | $ | (17 | ) | $ | (112 | ) | $ | (129 | ) | ||||
The Partnership estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. The Partnership validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. The Partnership estimates the option value of puts and calls combined into hedges, market prices, contract parameters and discount rates based on published LIBOR rates. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counterparties (or their affiliates) are also current or former bank lenders under the Partnership’s revolving credit facility. In addition, the Partnership routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change.
The following table sets forth a reconciliation of changes in the fair value of allocated derivative assets and liabilities classified as Level 3 in the fair value hierarchy and recorded in net gain (loss) on commodity derivatives in our Consolidated Statement of Operations for the years ended December 31, (in thousands):
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| Significant Unobservable Inputs | |||||||||||
| Level 3 | |||||||||||
| 2013 | 2012 | 2011 | |||||||||
| Beginning balance | $ | (112 | ) | $ | (1,198 | ) | $ | (1,108 | ) | ||
| Realized gains (losses) | (1,670 | ) | 5,965 | (1,130 | ) | ||||||
| Unrealized gains (losses) | (2,405 | ) | 1,086 | (90 | ) | ||||||
| Settlements paid (received) | 1,670 | (5,965 | ) | 1,130 | |||||||
| Ending balance | $ | (2,517 | ) | $ | (112 | ) | $ | (1,198 | ) | ||
| Change in unrealized gains (losses) included in earnings related to derivatives still held at period end | $ | (2,446 | ) | $ | (112 | ) | $ | (90 | ) | ||
During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.
See discussion regarding derivative classifications at Note 11.
Fair Value on a Non-Recurring Basis
The Partnership follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to the Partnership, ASC 820-10, applies to common stock issued for compensation purposes, the initial recognition of asset retirement obligations for which fair value is used and the considerations exchanged and certain nonfinancial assets and liabilities as may be acquired in business combinations.
The Partnership utilizes ASC Topic 718, “Compensation-Stock Compensation,” to value shares issued for compensation purposes. Measurement of share-based payment transactions with employees is generally based on the grant date fair value of the equity instruments issued.
Asset retirement cost estimates are derived from historical costs as well as the Partnership’s expectation of future cost to retire assets. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these measurements as Level 3.
The carrying amount of the Credit Facility of $78.5 million as of December 31, 2013 approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings. The revolving Credit Facility is classified as a Level 2 item within the fair value hierarchy.
The fair value of the consideration and assets acquired and liabilities assumed related to Acquisitions (See Note 2) are classified as a Level 3 item within the fair value hierarchy.
10. Contingent Consideration
A reconciliation of the beginning and ending balances of acquisition related accrued earnouts using significant unobservable inputs (Level 3) for the year ended December 31, is as follows (in thousands):
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| 2013 | |||
| Accrued earnout liability as of December 31, 2012 | $ | — | |
| Acquisition date fair value of contingent consideration - MCE Acquisition | 6,320 | ||
| Acquisition date fair value of contingent consideration - Southern Dome Acquired Properties | 1,600 | ||
| Change in fair value of contingent consideration | (1,600 | ) | |
| Payment of contingent consideration | — | ||
| Accrued earnout liability as of December 31, 2013 | $ | 6,320 | |
The owners of MCE are entitled to receive additional Partnership common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $120 million cap. The contingent consideration was valued at $6.3 million at the acquisition date and was considered as a part of the purchase price of MCE (See Note 2). The fair value of this liability will be valued quarterly and adjusted through earnings accordingly. The estimated fair value as of December 31, 2013 is $6.3 million and is presented in contingent consideration payable to related parties on the accompanying Consolidated Balance Sheets. The fair value of the contingent consideration was determined through the use of a Monte Carlo simulation, which takes a model with user-defined variables and runs it repeatedly, using a different value for each variable during each run, or trial. The simulation randomly generates the value used for each variable in each trial; however, the user defines permitted and most likely values of the variables through the use of probability distributions.
The Partnership agreed to provide additional consideration to Scintilla in November 2014 if the production attributable to the Southern Dome Acquired Properties for the nine-month period ending September 30, 2014 exceeds the average daily production of 383.5 Boe/d during the period between January 1, 2014 and September 30, 2014. We may satisfy any such additional consideration in cash, Partnership common units, or a combination thereof at our discretion. The contingent consideration was valued at $1.6 million at the acquisition date and was considered as part of the purchase price of the Southern Dome Acquired Properties (See Note 2). The fair value of the contingent consideration of $1.6 million, which represents the probability weighted contingent payment as a percentage of high, mid, and low production projections, was recorded in long term related party payables. The fair value of this liability will be adjusted through earnings accordingly. Based on current estimated production levels for the nine-month period ending September 30, 2014, the Partnership estimated the fair value as of December 31, 2013 is $0. The change in fair value of $1.6 million recorded as other income on the accompanying Consolidated Statements of Operations.
11. Derivatives
Due to the volatility of oil and natural gas prices, the Partnership periodically enters into price-risk management transactions (e.g., swaps, collars or puts) for a portion of its oil, natural gas and NGL production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the Partnership’s 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. The Partnership’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit the Partnership’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes.
Under ASC Topic 815, "Derivatives and Hedging," all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Company will net derivative assets and liabilities for counterparties where it has a legal right of offset. Changes in the derivatives' fair values are recognized currently in earnings since the Company has elected not to designate its current derivative contracts as hedges. . See discussion of fair value instruments at Note 9.
By using derivative instruments to mitigate exposures to changes in commodity prices, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk. The Partnership minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
The following table sets forth a reconciliation of the changes in fair value of the Partnership's commodity derivatives for the years ended December 31, 2013, 2012, and 2011 (in thousands).
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| 2013 | 2012 | 2011 | |||||||||
| Beginning fair value of commodity derivatives | $ | (129 | ) | $ | (1,199 | ) | $ | (1,349 | ) | ||
| Total gain (loss) on commodity derivatives | (5,548 | ) | 7,057 | (1,349 | ) | ||||||
| Commodity derivative premiums paid | 1,334 | — | — | ||||||||
| Commodity derivative cash settlements paid (received) | 1,929 | (5,987 | ) | 1,499 | |||||||
| Ending fair value of commodity derivatives | $ | (2,414 | ) | $ | (129 | ) | $ | (1,199 | ) | ||
Certain of our commodity derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our commodity derivative instruments, presenting the impact of offsetting the derivative assets and liabilities recorded in other assets and derivative obligations on our Consolidated Balance Sheets as of December 31 for the periods indicated below (in thousands):
| December 31, 2013 | |||||||||||
| Gross Amounts of Recognized Assets and Liabilities | Gross Amounts Offset in the Consolidated Balance Sheet | Net Amounts Presented in the Consolidated Balance Sheet | |||||||||
| Offsetting Derivative Assets: | |||||||||||
| Commodity derivatives | $ | 2,980 | $ | (2,190 | ) | $ | 790 | ||||
| Offsetting Derivative Liabilities: | |||||||||||
| Commodity Derivatives | $ | (5,394 | ) | $ | 2,190 | $ | (3,204 | ) | |||
| December 31, 2012 | |||||||||||
| Gross Amounts of Recognized Assets and Liabilities | Gross Amounts Offset in the Consolidated Balance Sheet | Net Amounts Presented in the Consolidated Balance Sheet | |||||||||
| Offsetting Derivative Assets: | |||||||||||
| Commodity derivatives | $ | 52 | $ | (27 | ) | $ | 25 | ||||
| Offsetting Derivative Liabilities: | |||||||||||
| Commodity Derivatives | $ | (181 | ) | $ | 27 | $ | (154 | ) | |||
The follow table presents the fair value of derivative instruments outstanding as of December 31, (in thousands):
| Oil collars: | Volumes (Bbls) | Floor Price | Ceiling Price | ||||||||
| 2014 | 80,444 | $ | 80.00 | $ | 103.50 | ||||||
| 2015 | 42,649 | $ | 80.00 | $ | 93.25 | ||||||
| Natural gas collars: | Volumes (MMBtu) | Floor Price | Ceiling Price | ||||||||
| 2014 | 1,528,083 | $ | 4.00 | $ | 4.41 | ||||||
| 2015 | 1,364,382 | $ | 4.00 | $ | 4.32 | ||||||
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| Oil put options: | Volumes (Bbls) | Floor Price | |||||
| 2014 | 24,547 | $ | 80.00 | ||||
| Natural gas put options: | Volumes (MMBtu) | Floor Price | |||||
| 2014 | 445,768 | $ | 3.50 | ||||
| 2015 | 798,853 | $ | 3.50 | ||||
| 2016 | 930,468 | $ | 3.50 | ||||
| Natural gas liquids put options: | Volumes (Bbls) | Average Floor Price | |||||
| 2014 | 59,423 | $ | 28.66 | ||||
| Oil swaps: | Volumes (Bbls) | Fixed Price per Bbl | ||||||
| 2014 | 14,634 | $ | 90.20 | |||||
| 2015 | 39,411 | $ | 88.90 | |||||
| 2016 | 36,658 | $ | 86.00 | |||||
| Natural gas swaps: | Volumes (MMBtu) | Average Price per MMBtu | ||||||
| 2014 | 1,102,183 | $ | 4.09 | |||||
| 2015 | 800,573 | $ | 4.25 | |||||
| 2016 | 629,301 | $ | 4.37 | |||||
| Natural gas liquid swaps: | Volumes (MMBtu) | Average Price | ||||||
| 2014 | 643,779 | $ | 39.79 | |||||
| 2015 | 84,793 | $ | 82.74 | |||||
| Oil swaps: | Volumes (Bbls) | Fixed Price per Bbl | |||||
| 2013 | 41,843 | $ | 93.05 | ||||
| 2014 | 15,905 | $ | 90.20 | ||||
| Natural gas liquids put options: | Volumes (Bbls) | Average Floor Price | |||||
| 2013 | 89,333 | $ | 40.71 | ||||
| 2014 | 34,410 | $ | 39.39 | ||||
| Natural gas swaps: | Volumes (MMBtu) | Average Price per MMBtu | |||||
| 2013 | 436,105 | $ | 3.60 | ||||
12. Unitholders' Equity
The Units
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.
Common Units
The common units have limited voting rights as set forth in our partnership agreement.
Subordinated Units
All of the subordinated units are held by New Source. The partnership agreement provides that, during the subordination period, the common units have the right to receive distributions of Available Cash from Operating Surplus (each as defined in the Partnership’s agreement) each quarter in an amount equal to $0.525 per common unit (the “Minimum Quarterly Distribution”), plus any arrearages in the payment of the Minimum Quarterly Distribution from Operating Surplus on the 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 will not be entitled to receive any distributions from Operating Surplus until the common units have received the Minimum Quarterly Distribution plus any arrearages from prior quarters. 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/day 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. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash from Operating Surplus to be distributed on the common units. 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 (125.0% 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 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. For purposes of the subordination period, any quarter in which holders of our subordinated units are not entitled to receive the distributions otherwise payable on the subordinated units pursuant to the minimum annual production requirement under the development agreement shall be included
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in any period of twelve consecutive quarters with respect to (i), so long as 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.
Incentive Distribution Rights
The General Partner currently holds the Incentive Distribution Rights (“IDRs”), but may transfer these rights separately from its general partner interest, subject to restrictions in the Partnership Agreement. The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and the General Partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the General Partner and the unitholders 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. The percentage interests set forth below for the General Partner include its 2.0% general partner interest, assume the General Partner has contributed any additional capital necessary to maintain its 2.0% general partner interest and has not transferred its IDRs and there are no arrearages on common units.
| Total Quarterly | Marginal Percentage Interest in Distributions | |||||
| Distributions per Unit | Unitholders | General Partner | ||||
| Minimum Quarterly Distribution | $0.525 | 98% | 2% | |||
| First Target Distribution | up to $0.60375 | 98% | 2% | |||
| Second Target Distribution | above $0.60375 up to $0.65625 | 85% | 15% | |||
| Thereafter | above $0.65625 | 75% | 25% | |||
Cash Distributions
The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common, subordinated and general partner units during the year ended December 31, 2013, as shown in the following table (in thousands, except distribution per unit):
| 2013 Distribution | Per Common Unit | Amount Paid to Common Unitholders | Amount Paid to Subordinated Unitholder | Amount Paid to General Unitholder | Total Distributions | |||||||||||||||
| First Quarter | $ | 0.2742 | (1) | $ | 1,857 | $ | 605 | $ | 43 | $ | 2,504 | |||||||||
| Second Quarter | $ | 0.5500 | $ | 3,725 | $ | 1,213 | $ | 85 | $ | 5,023 | ||||||||||
| Third Quarter | $ | 0.5750 | $ | 3,895 | $ | 1,268 | $ | 89 | $ | 5,252 | ||||||||||
| Fourth Quarter | $ | 0.5750 | (2)(3) | $ | 4,400 | $ | 1,268 | $ | 89 | $ | 5,757 | |||||||||
| (1) | Prorated to reflect 47 days of quarterly cash distribution rate of $0.525 per unit. |
| (2) | Distributions of $1.1 million were not paid on the 1,947,033 common units issued in conjunction with the MCE acquisition pursuant to an arrangement with sellers to forgo, with respect to such common units, their rights to distribution for the fourth quarter 2013 only. |
| (3) | Distribution was declared on January 21, 2014. Distributions of $0.3 million were paid on the 488,667 common units issued in conjunction with the CEU Acquisition in January 2014 due to the record date for the fourth quarter distribution being January 31, 2014. The fourth quarter distributions are not reflected in these financial statements. |
Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors. The Partnership’s partnership agreement requires that, within 45 days after the end of each quarter, the Partnership distribute all of its available cash (as defined in the partnership agreement) to the partners of record on the applicable record date.
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Non-controlling Interest:
As part of the MCE Acquisition mentioned, certain owners of MCE retained Class B Units in MCE LP. The MCE, LP 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 at MCE. The Class B Units are classified as a separate equity classification titled non-controlling interest on 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 New Source Energy Partners L.P. on the Consolidated Statements of Operations.
The following table illustrates the percentage 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. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the Class A and Class B unitholders in any available cash from operating surplus the MCE Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.”
| Marginal Percentage Interest in Distributions | ||||||
| Total Quarterly Distributions per MCE Unit | MCE Class A Unitholders (the Partnership) | MCE Class B Unitholders | ||||
| Minimum Quarterly Distribution | $15,820 | 100% | —% | |||
| First Target Distribution | Above $18,194 up to $19,776 | 85% | 15% | |||
| Second Target Distribution | Above $19,776 up to $23,731 | 75% | 25% | |||
| Third Target Distribution and Thereafter | Above $23,731 | 50% | 50% | |||
13. Earnings Per Common and Subordinated Unit
The computations of basic earnings per common unit and subordinated unit are based on the weighted average number of common units and subordinated units, respectively, outstanding during the applicable period. The Partnership’s subordinated units meet the definition of a participating security; therefore, the Partnership is required to use the two-class method in the computation of earnings per unit. Basic earnings per common unit and subordinated unit are determined by dividing net income allocated to the common units and subordinated units, respectively, after deducting the amount allocated to the Partnership’s general partner (including distributions to the general partner on its IDRs), by the weighted average number of outstanding common units and subordinated units, respectively, during the period. The Partnership has no potential common units outstanding. Therefore, the amounts of basic and diluted earnings per unit are the same.
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 2% of earnings to the General Partner, reflect that, while such distribution to the General Partner with respect to its 2% general partner interest was made, no incentive distributions were permitted to be, or were, made to the General Partner because quarterly distributions declared by the board of directors for the fourth quarter of 2013 did not exceed the specified targets.
Basic and diluted earnings per unit for the period from February 13, 2013 through December 31, 2013 were computed using the following components:
| Common Units | Subordinated Units | General Partner | |||||||||
| Numerator: | |||||||||||
| Net income (in thousands) | $ | 16,929 | $ | 4,099 | $ | 291 | |||||
| Denominator: | |||||||||||
| Weighted average units outstanding | 6,994,517 | 2,205,000 | 154,673 | ||||||||
| Basic and diluted income per unit | $ | 2.42 | $ | 1.86 | $ | 1.88 | |||||
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EPU for periods prior to Feb 13, 2013 is not presented because the data would not be meaningful due to the change in tax status that took place on Feb 13, 2013.
14. Equity-Based Compensation
On February 13, 2013, the Partnership granted 367,500 units of restricted common units to consultants, officers and other employees. Disposition of the units is restricted until the later of the termination of the subordination period or December 31, 2015. The award was valued at the IPO price of $20.00 per common unit and charged to equity-based compensation in general and administrative expenses at the date of the award. The restricted units do not contain a future service requirement from the recipients, so the amounts were fully vested as of February 13, 2013 and 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 valued at $2.3 million that were included as part of the purchase price, which were all outstanding as of December 31, 2013. The units will vest over the period of three years, and are subject to vesting restrictions based on employment status. If such common units are forfeited for any reason prior to vesting, then within forty-five days of the end of each calendar year beginning on December 31, 2014, the Partnership will issue to those units forfeited by the employee to the former MCE owners. Equity-based compensation expense will be recognized straight-line over the three-year vesting period for fair value of these units. For the year ended December 31, 2013, the Partnership recognized $0.1 million in equity-based compensation expense and is presented as "Unit compensation funded by unitholders" on the accompanying Consolidated Statements of Partners' Capital and as general and administrative expense in the accompanying Consolidated Statements of Operations for the year ended December 31, 2013.
Unamortized equity-based compensation expense related to these awards was $2.1 million as of December 31, 2013 and will be recognized on a straight line basis over 2.8 years.
On August 18, 2011, New Source granted 2,900,000 shares of restricted common stock, with 1,000,000 shares vesting upon the first anniversary of the date of grant, 700,000 shares vesting on the second anniversary of the date of grant, and the remaining 1,200,000 shares vesting on the completion of the initial public offering of New Source's common stock pursuant to a filed prospectus provided that the employees remain employed by New Source on the applicable vesting dates subject to limited exceptions ("2011 Grant"). For periods January 1, 2013 to February 13, 2013, an allocated amount of New Source stock-based compensation related to these awards was recognized in the Partnership’s financial statements in the amount of $0.4 million as general and administrative expense in the accompanying Consolidated Statements of Operations for the year ended December 31, 2013.
Equity-based compensation expense for the year ended December 31, 2012 and 2011 reflects an allocated amount of stock-based compensation expense from the 2011 Grant. Equity-based compensation expense for 2012 was the result of the amortization of the value to expense over the vesting periods for which there are fixed vesting terms of the awards. Accordingly, the Partnership recorded $8.2 million and $4.5 million of stock-based compensation as general and administrative expense in the accompanying Consolidated Statements of Operations for the years ended December 31, 2012 and 2011, respectively.
15. Segment Information
In accordance with FASB ASC 280, Segment Reporting, the Partnership routinely evaluates whether it has separate operating and reportable segments. The Partnership has determined that it operates in two reportable operating segments, which are referred to as the Exploration and Production Segment and the Oilfield Services Segment. This determination is based on the following factors: (1) the Partnership’s chief operating decision maker is currently managing each segment as a
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separate business and evaluating the performance of each segment and making resource allocation decisions distinctly and expects to do so for the foreseeable future, and (2) discrete financial information for each segment is available. The following is a brief description of the Partnership’s operating segments:
Exploration and Production Segment. The Exploration and Production Segment focuses on non-operated exploration, development and production of the Partnership’s onshore oil and natural gas properties portfolio of properties that extends across conventional resource reservoirs in east-central Oklahoma.
Oilfield Services Segment. The Oilfield Services Segment offers full service blowout prevention installation and pressure testing services throughout the Mid-Continent region, along with the provision of certain ancillary equipment necessary to perform such services. The Oilfield Services Segment was acquired through the MCE Acquisition, which was completed on November 12, 2013.
The following tables set forth certain financial information for our two operating segments as of and for the year ended December 31, 2013 (amounts in thousands):
| Exploration and Production Segment | Oilfield Services Segment | Total | |||||||||
| Identifiable assets | $ | 181,440 | $ | 73,270 | $ | 254,710 | |||||
| Revenues | $ | 46,937 | $ | 3,738 | $ | 50,675 | |||||
| Operating costs | (15,300 | ) | (2,040 | ) | (17,340 | ) | |||||
| Segment margin | $ | 31,637 | $ | 1,698 | $ | 33,335 | |||||
| Depreciation and amortization | $ | 16,590 | $ | 1,966 | $ | 18,556 | |||||
| Capital expenditures | $ | 48,319 | $ | 445 | $ | 48,764 | |||||
The following table reconciles the segment profits reported above to operating loss as reported on the Consolidated Statements of Operations for the year ended December 31, (amounts in thousands):
| 2013 | |||
| Segment margin | $ | 33,335 | |
| Depreciation and amortization | (18,556 | ) | |
| General and administrative | (14,760 | ) | |
| Accretion expense | (209 | ) | |
| Operating loss | $ | (190 | ) |
16. 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, as set forth in Note 3, 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 their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.
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On February 13, 2013, in connection with the closing of the Offering, NSLP entered into a development agreement (the “Development Agreement”) by and among NSLP, New Source and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, NSLP has agreed to maintain an average annual maintenance drilling budget of at least $8.2 million to drill certain of NSLP’s proved undeveloped locations and maintain NSLP’s producing wells.
Pursuant to the Development Agreement, the General Partner will, at least annually, at its discretion, determine NSLP’s maintenance drilling budget. The General Partner will also have the right to propose which wells are drilled based on NSLP’s maintenance drilling budget. Under the Development Agreement, New Dominion will use its commercially reasonable best efforts to (i) conduct its operations such that NSLP’s proportionate share of capital expenses that it would consider maintenance capital under the Participation Agreement is equal to the annual maintenance drilling budget set by the General Partner and (ii) cause the wells drilled pursuant to the Participation Agreement to be consistent with the maintenance drilling schedule proposed by the General Partner. The General Partner will also have the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.
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 and natural gas 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.
Legal Matters
New Dominion is a defendant in a legal proceeding arising in the normal course of its business, which may impact the Partnership as described below.
In the case of Mattingly v. Equal Energy, LLC, New Dominion is a named defendant. In this case, the plaintiffs assert claims on behalf of a class of royalty owners in wells operated by New Dominion and others from which natural gas is sold by New Dominion to Scissortail Energy, LLC. The plaintiffs assert that royalties to the class should be paid based upon the price received by Scissortail for the gas and its components at the tailgate of the plant, rather than the price paid by Scissortail at the wellhead where the gas is purchased. The plaintiffs assert a variety of breach of contract and tort claims. The case was originally filed in the District Court of Creek County, Oklahoma and was removed by the defendants to the federal court but was remanded to state court on August 1, 2011.
If liability does attach to New Dominion as operator, New Dominion would look to the working interest owners to pay their proportionate share of any liability. While the outcome and impact on the Partnership of this proceeding cannot be predicted with certainty, management believes a range of loss from $10,000 to $250,000 may be reasonably possible.
The Partnership may be involved in other various routine legal proceedings incidental to its business from time to time. However, there were no other material pending legal proceedings to which the Partnership is a party or to which any of its assets are subject.
Lease Obligations
The following is schedule by year of lease obligations and minimum lease payments for non-cancellable leases with a term of more than one year at December 31, 2013 (in thousands):
| Year | Operating Leases | ||
| 2014 | $ | 175 | |
| 2015 | 88 | ||
| 2016 | 3 | ||
| Total | $ | 266 | |
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17. Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for the years ended December 31, 2013 and 2012 (in thousands, except per unit data):
| Quarter Ended | |||||||||||||||
| 2013 | March 31 (1) (2) | June 30 | September 30 | December 31 | |||||||||||
| Revenues | $ | 9,360 | $ | 10,649 | $ | 12,431 | $ | 18,235 | |||||||
| Income (loss) from operations | (6,118 | ) | 2,456 | 2,121 | 1,351 | ||||||||||
| Income tax (expense) benefit | 12,126 | — | — | — | |||||||||||
| Net income (loss) | $ | (1,397 | ) | $ | 8,151 | $ | (1,986 | ) | $ | 21,854 | |||||
| Earnings (loss) per unit | |||||||||||||||
| Basic | $ | (0.87 | ) | $ | 0.89 | $ | (0.22 | ) | $ | 2.05 | |||||
| Diluted | $ | (0.87 | ) | $ | 0.89 | $ | (0.22 | ) | $ | 2.05 | |||||
| 2012 (2) | |||||||||||||||
| Revenues | $ | 10,031 | $ | 8,156 | $ | 8,262 | $ | 9,147 | |||||||
| Income (loss) from operations | (354 | ) | (1,919 | ) | 1,009 | 2,314 | |||||||||
| Income tax (expense) benefit | 144 | (1,871 | ) | 562 | (631 | ) | |||||||||
| Net income (loss) | $ | (108 | ) | $ | 2,921 | $ | (799 | ) | $ | 1,095 | |||||
| (1) | The first quarter, 2013 loss per unit only applies to earnings from February 14, 2013 (the Partnership's IPO date) to December 31, 2013. |
| (2) | EPU for periods prior to Feb 13, 2013 is not presented because the data would not be meaningful due to the change in tax status that took place on Feb 13, 2013. |
18. Subsequent Events
CEU Acquired Properties
On January 31, 2014, we completed the acquisition of the CEU Acquired Properties, which included working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma from CEU Paradigm, LLC.
As consideration for the working interests, we paid $6.9 million in cash to the seller at closing and issued 488,667 common units valued at $23.51 per common unit to the seller. We also agreed to provide additional consideration to the seller in November 2014 if the production attributable to the working interests for the nine-month period ending September 30, 2014 exceeds a certain production average, which was valued at $2.3 million on the acquisition date and is part of the purchase price. We may satisfy any such additional consideration in cash, common units, or a combination thereof at our discretion. Total consideration for the acquisition was $20.7 million.
Other
On January 8, 2013, MCE entered into five separate loan agreements with G.E. Financial. These notes are for five separate pieces of equipment with loan amounts ranging from $141,842 to $251,110. Each note begins payments in February 2014 and range of principal amounts from $4,303 to $7,613 monthly, with interest at 5.75% over 48 months, maturing in January 2018. Each of the notes is collateralized by specific pieces of equipment.
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On February 11, 2014, MCE entered into a loan agreement with Bank of Oklahoma. The note evidences a revolving line of credit of up to $4.0 million, based on a borrowing base related to the Oilfield Service Segment's accounts receivable, with interest only payments due monthly, maturing February 10, 2016. The note replaced MCE's factoring agreement (See Note 7). The interest rate on this note is BOKF National Prime Rate. This note is secured by accounts receivable, inventory, chattel paper and general intangibles of MCE.
On March 10, 2014, MCE entered into a loan agreement with Legacy Bank. The note is for $2,484,703 with payments of $58,173 over 48 months at an interest rate of 5.75%, and it matures March 10, 2018. The note is secured by certain vehicles owned by MCE.
On January 21, 2014, our general partner's board of directors approved a cash distribution of $0.575 per unit payable on February 14, 2014 to unitholders of record on January 31, 2014.
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Unaudited Supplementary Information
Supplemental Oil and Natural Gas Information
Information with respect to oil and natural gas producing activities is presented in the following tables. Estimates of reserve quantities were determined by an independent petroleum engineering firm as of December 31, 2013 and 2012, and all of this information is unaudited.
Oil and Natural Gas Properties
The following table summarizes the capitalized costs related to oil, natural gas and NGLs, producing activities and related accumulated depletion and amortization, as of December 31, (in thousands);
| 2013 | 2012 | |||||||
| Proved | $ | 291,829 | $ | 202,795 | ||||
| Less: accumulated depreciation, depletion and amortization | (128,961 | ) | (112,372 | ) | ||||
| Net capitalized costs for oil and natural gas properties | $ | 162,868 | $ | 90,423 | ||||
Costs Incurred for Oil and Natural Gas Producing Activities
The following table summarizes the costs incurred for oil, natural gas and NGLs producing activities during the years ended December 31, (in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Property acquisition costs | $ | 58,014 | $ | — | $ | — | |||||
| Development costs | 29,451 | 11,382 | 22,657 | ||||||||
| Total costs incurred | $ | 87,465 | $ | 11,382 | $ | 22,657 | |||||
No internal costs or interest expense were capitalized in 2013, 2012 and 2011.
Reserve Quantity Information
The following information represents estimates of proved reserves as of December 31, 2013, 2012 and 2011. The pricing used for estimates of reserves as of December 31, 2013, 2012 and 2011, was based on an unweighted twelve-month average West Texas Intermediate posted price of $96.78, $94.71 and $96.19, respectively, per Bbl for oil and a Henry Hub spot natural gas price of $3.67, $2.76 and $4.12, respectively, per Mcf for natural gas. Natural gas liquids ("NGL") were priced at 38%, 36% and 52% of the oil prices for the periods ended December 31, 2013, 2012 and 2011, respectively, which approximates the realizable value received.
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, 2013, 2012 and 2011 are based on reports prepared by independent reserve engineers Ralph E. Davis Associates, Inc. Proved reserves for all periods presented were estimated in accordance with the guidelines established by the SEC and the FASB.
The following table summarizes the prices utilized in the reserve estimates as adjusted for location, grade and quality as of December 31,:
| 2013 | 2012 | 2011 | |||||||||
| Oil | $ | 93.71 | $ | 92.74 | $ | 92.95 | |||||
| Gas | $ | 3.55 | $ | 2.59 | $ | 3.84 | |||||
| Natural gas liquids | $ | 35.61 | $ | 33.39 | $ | 48.33 | |||||
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
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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 following table provides a rollforward of the total net proved reserves for the years ended December 31, 2011, 2012 and 2013, 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.
| Oil (Bbls) | Natural Gas (Mcf) | NGL (Bbls) | Total (Boe)(1) | ||||||||
| Total proved reserves | |||||||||||
| Balance, January 1, 2011 | 286,260 | 21,549,260 | 7,487,970 | 11,365,773 | |||||||
| Revisions(2) | 88,170 | (4,568,868 | ) | (562,175 | ) | (1,235,483 | ) | ||||
| Extensions and discoveries(3) | 627,770 | 7,003,650 | 3,102,760 | 4,897,805 | |||||||
| Production | (48,770 | ) | (2,378,232 | ) | (720,615 | ) | (1,165,757 | ) | |||
| Balance, December 31, 2011 | 953,430 | 21,605,810 | 9,307,940 | 13,862,338 | |||||||
| Proved developed reserves | 276,240 | 11,125,330 | 5,323,650 | 7,454,112 | |||||||
| Proved undeveloped reserves | 677,190 | 10,480,480 | 3,984,290 | 6,408,227 | |||||||
| Total proved reserves | 953,430 | 21,605,810 | 9,307,940 | 13,862,339 | |||||||
| Balance, January 1, 2012 | 953,430 | 21,605,810 | 9,307,940 | 13,862,339 | |||||||
| Revisions | (469,630 | ) | 1,295,502 | 57,825 | (195,888 | ) | |||||
| Purchases of reserves | 1,031,040 | 11,889,850 | 4,727,060 | 7,739,742 | |||||||
| Extensions and discoveries(3) | 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(3) | 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 | 12,483,598 | |||||||
| Proved undeveloped reserves | 517,390 | 16,625,240 | 4,866,670 | 8,154,960 | |||||||
| Total proved reserves | 1,439,580 | 36,250,430 | 13,157,240 | 20,638,558 | |||||||
| (1) | Determined using the ratio of 6 Mcf gas to 1 Bbl oil. |
| (2) | The revisions in proved reserves in 2011 were due to revisions to the proved developed producing forecasts subsequent to the acquisition of these assets from Scintilla, to more closely match the historical production performance. |
| (3) | Extensions and discoveries are due to development drilling in the Golden Lane area. |
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Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by applying the twelve-month unweighted average of the first-day-of-the-month pricing for oil, 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.
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 of discounted future net cash flows as of December 31, (in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Future production revenues | $ | 732,340 | $ | 435,670 | $ | 621,378 | |||||
| Future costs: | |||||||||||
| Production | (223,582 | ) | (121,541 | ) | (138,297 | ) | |||||
| Development | (110,881 | ) | (52,032 | ) | (86,630 | ) | |||||
| Income tax expense(1) | — | (85,090 | ) | (132,758 | ) | ||||||
| 10% annual discount for estimated timing of cash flows | (185,152 | ) | (82,746 | ) | (110,360 | ) | |||||
| Standardized measure of discounted net cash flows | $ | 212,725 | $ | 94,261 | $ | 153,333 | |||||
| (1) | Our standardized measure as of December 31, 2012 and 2011 includes effects of income taxes. The Partnership was not a taxable entity in 2013. |
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table provides a rollforward of the standardized measure of discounted future net cash flows for the years ended December 31, (in thousands):
| 2013 | 2012 | 2011 | |||||||||
| Discounted future net cash flows at beginning of year | $ | 94,261 | $ | 153,333 | $ | 129,331 | |||||
| Increase (decrease) | |||||||||||
| Sales and transfers, net of production costs | (31,637 | ) | (28,235 | ) | (36,230 | ) | |||||
| Net changes in prices and production costs | 3,952 | (93,618 | ) | 56,858 | |||||||
| Extensions and discoveries | 25,280 | 8,688 | 75,830 | ||||||||
| Changes in future development costs | (61,939 | ) | 8,350 | (27,895 | ) | ||||||
| Previous development costs incurred | 29,451 | 11,382 | 22,657 | ||||||||
| Acquisition of reserves in place | 76,596 | — | — | ||||||||
| Revisions of previous quantity estimates | (7,035 | ) | (5,833 | ) | (19,128 | ) | |||||
| Changes in income taxes | 47,387 | 33,532 | (80,919 | ) | |||||||
| Timing and other | 26,983 | (8,671 | ) | 19,896 | |||||||
| Accretion of discount | 9,426 | 15,333 | 12,933 | ||||||||
| Net increase (decrease) | 118,464 | (59,072 | ) | 24,002 | |||||||
| Discounted future net cash flows at end of year | $ | 212,725 | $ | 94,261 | $ | 153,333 | |||||
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| 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, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2013.
The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the 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, 2013 at the reasonable assurance level due to a material weakness in internal control over financial reporting. The material weakness we identified related to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review 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 United States generally accepted accounting principles. In the current period these non-routine transactions impacted the recording of equity based compensation, cash-flow presentations, required business combination adjustments and disclosures and calculation of earnings (loss) per unit in accordance with United States generally accepted accounting principles. The material weakness resulted in the recording of adjustments identified by our independent registered public accounting firm to the consolidated financial statements for the periods ended March 31, 2013 and December 31, 2013. Notwithstanding the existence of the material weakness, 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 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, 2013, the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of its internal control over financial reporting using the criteria in the 1992 edition of the framework 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, 2013. The material weakness we identified related to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review 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 United States generally accepted accounting principles. In the current period these non-routine transactions impacted the recording of equity based compensation, cash-flow presentations, required business combination adjustments and disclosures and calculation of earnings (loss) per unit in accordance with United States generally accepted accounting principles. The material weakness resulted in the recording of adjustments identified by our independent registered public accounting firm to the consolidated financial statements for the periods ended March 31, 2013 and December 31, 2013. Notwithstanding the existence of the material weakness, 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.
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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.
Remediation of Material Weaknesses in Internal Control Over Financial Reporting
With the oversight of senior management and our audit committee, we have begun to take steps intended to address the underlying causes of the material weakness, primarily through the engagement of outside consulting firms, hiring of personnel with technical accounting and financial reporting experience, and the implementation and validation of improved accounting and financial reporting procedures.
As of December 31, 2013, we have not yet been able to remediate this material weakness. We do not know the specific time frame needed to remediate all of the control deficiencies underlying this material weakness. In addition, we may need to incur incremental costs associated with this remediation, primarily due to engagement with such firms, and the implementation and validation of improved accounting and financial reporting procedures. As we continue to evaluate and work to improve our internal control over financial reporting, we may determine to take additional measures to address the material weakness.
Changes in Internal Control Over Financial Reporting
The acquisition of MCE has added additional controls that we must evaluate related to the financial statements of MCE and our consolidation process for the preparation of our consolidated financial statements. Other than as described above, there have not been any changes in our internal control over financial reporting during the quarter ended December 31, 2013, which have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
| ITEM 9B. | OTHER INFORMATION |
None.
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PART III.
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Management of New Source Energy Partners L.P.
New Source Energy GP, LLC, our general partner, manages our operations and activities on our behalf. As of March 31, 2014, our general partner is owned 5.6% by New Source Energy, 25.0% by an entity controlled by David J. Chernicky, the Chairman of our general partner, and 69.4% by an entity controlled by Kristian B. Kos, the President and Chief Executive Officer of our general partner. All of our executive management personnel are employees of New Source Energy, and devote their time as needed to conduct our business and affairs.
Our general partner has a board of directors that oversees its management, operations and activities. 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 us to incur indebtedness or other obligations that are nonrecourse to it. Except for limited circumstances under our partnership agreement, and subject to its fiduciary duty to act in good faith, our general partner will have exclusive management power over our business and affairs.
Board Leadership Structure and Role in Risk Oversight
Leadership of our general partner’s board of directors is vested in a Chairman of the Board. Although our Chief Executive Officer currently does not serve as Chairman of the board of directors of our general partner, we currently have no policy prohibiting our current or any future chief executive officer from serving as Chairman of the Board. The board of directors, in recognizing the importance of the board of directors having the ability to operate independently, determined that separating the roles of Chairman of the Board and Chief Executive Officer is advantageous for us and our unitholders. Our general partner’s board of directors has also determined that having the Chief Executive Officer serve as a director enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations, and ultimately improves the ability of the board of directors to perform its oversight role.
The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise-level risk management, while retaining responsibility for oversight of our executive officers in that regard. Our executive officers will offer an enterprise-level risk assessment to the board of directors at least once every year.
Directors and Executive Officers
The following table sets forth certain information regarding the current directors and executive officers of our general partner.
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| Name | Age | Position | ||
| David J. Chernicky | 60 | Chairman of the Board and Senior Geologist | ||
| Kristian B. Kos | 36 | Director, President and Chief Executive Officer | ||
| Richard D. Finley | 63 | Chief Financial Officer and Treasurer | ||
| Carol T. Bryant | 56 | Senior Engineer | ||
| Terry L. Toole | 69 | Director | ||
| V. Bruce Thompson | 66 | Director | ||
| Phil Albert | 54 | Director | ||
| John A. Raber | 60 | Director | ||
| Charles Lee Reynolds III | 63 | Director | ||
| Dikran Tourian | 37 | Director | ||
Our general partner’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. In selecting and appointing directors to the board of directors, the owners of our general partner do not intend to apply a formal diversity policy or set of guidelines. However, when appointing new directors, the owners of our general partner will consider each individual director’s qualifications, skills, business experience and capacity to serve as a director, as described below for each director, and the diversity of these attributes for the board of directors as a whole.
David J. Chernicky—Chairman of the Board and Senior Geologist—David J. Chernicky was appointed Chairman of the Board and Senior Geologist of our general partner in October 2012. David J. Chernicky has also served as the chairman of the board and senior geologist of New Source Energy since August 2011 and has more than 31 years of experience in the oil and gas industry. On July 1, 1998, Mr. Chernicky co-founded New Dominion, an oil and gas exploration and production company based in Tulsa, Oklahoma. Mr. Chernicky beneficially owns New Dominion and Scintilla. From April 2002 until his resignation on August 1, 2011, Mr. Chernicky served as the president and manager of Scintilla and New Dominion, overseeing those companies’ operations as a whole. Mr. Chernicky currently serves on the boards of various governmental bodies, including the Grand River Dam Authority (“GRDA”) and the Oklahoma Ordinance Works Authority. Prior to founding New Dominion, Mr. Chernicky was employed in 1979 as a geologist for Marathon Oil in Casper, Wyoming and later, from 1979 until 1983 as a geologist and geophysicist for Amoco Production in Denver, Colorado. Thereafter, Mr. Chernicky worked as an independent consulting geologist until founding New Dominion, LLC. Mr. Chernicky graduated from the University of Oklahoma in 1978 with a Bachelor of Science degree in exploration geophysics. We believe Mr. Chernicky’s extensive experience in the oil and gas industry, his leadership positions at other oil and gas companies, his reservoir engineering skills and his knowledge regarding our business and operations brings important experience and leadership to the board of directors.
Kristian B. Kos—President and Chief Executive Officer, Director—Kristian B. Kos was appointed President and Chief Executive Officer of our general partner in October 2012. Kristian B. Kos has also served as the president and chief executive officer and director of New Source Energy since July 2011 and has been involved in oil and gas and energy industries since 2005. From May 2010 through July 2011, Kristian B. Kos provided consulting services to New Dominion. In August 2006, Mr. Kos founded Deylau, LLC, a company focused on identifying, managing and financing oil and gas production companies, and served as its manager from August 2006 to July 2011. From February 2006 to February 2007, Mr. Kos served as a Vice President at Diamondback Energy Services, where he was actively involved in identifying and executing growth strategies for that company, including acquisitions. From September 2005 to February 2006, Mr. Kos worked in a business-development role for Gulfport Energy. Prior to working in the oil and gas and energy sectors, Mr. Kos worked in the financial sector for hedge fund manager Wexford Capital LP. Mr. Kos currently serves as a director and, through Deylau, is the majority stockholder of Encompass Energy Services, Inc. Mr. Kos earned Bachelor of Arts and Master of Arts degrees in Economics and Philosophy from Trinity College, Dublin, Ireland in 1999. He also earned a Master of Philosophy degree in Economics from the University of Aix-Marseille, France in 2000. We believe Mr. Kos’s experience in the financial and oil and gas industries, his leadership positions at other oil and gas companies, and his knowledge regarding our business and operations provides important experience and leadership to the board of directors.
Richard D. Finley—Chief Financial Officer and Treasurer—Richard D. Finley, C.P.A. was appointed Chief Financial Officer and Treasurer of our general partner in October 2012. Mr. Finley has also served as the chief financial officer and treasurer of New Source Energy since August 2011 and is partner at Finley & Cook, PLLC, an Oklahoma certified public accounting firm. Mr. Finley transitioned out of his role as a partner at Finley & Cook, where he worked since 1973, overseeing tax and accounting services within various industries and business environments. Mr. Finley has extensive experience with oil and gas exploration and production clients in general matters of accounting and taxation. Mr. Finley earned a Bachelor degree
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in accounting from Central State University, Edmond, Oklahoma, in 1973. He has been a Certified Public Accountant since 1975 and is a member of both the Oklahoma Society of Certified Public Accountants and the American Institute of Certified Public Accountants. He is also a Certified Valuation Analyst and a member of the National Association of Certified Valuation Analysts.
Carol T. Bryant—Senior Engineer—Carol T. Bryant was appointed Senior Engineer of our general partner in October 2012. Ms. Bryant has also served as the senior engineer for New Source Energy Corporation from August 2011 to December 31, 2013. Prior to joining New Source Energy, Ms. Bryant was a consulting petroleum engineer for Pinnacle Energy Services from June 2008 to April 2011 where she prepared third party reserve and engineering reports for clients with assets in the Mid-Continent region. From April 2007 to May 2008, Ms. Bryant was the senior reservoir engineer for Windsor Energy Resources, LLC and Gulfport Energy/Grizzly Oil Sands, LLC, responsible for corporate reserve evaluation and database development, facilitating bank engineering reviews and investor reserve reporting. From May 2000 to April 2007, Ms. Bryant held various reservoir engineering positions with Chaparral Energy, LLC in Oklahoma City. She was the corporate reserve manager responsible for quarterly, year-end and special reporting requirements and facilitated third party and bank engineering reviews. She initiated organizational changes to meet the needs of a rapidly growing reserve base and in preparation to meet IPO reporting requirements and Sarbanes-Oxley compliance. As a senior reservoir engineer at Chaparral, Ms. Bryant developed geologic and reservoir simulation models to evaluate CO2 reserve potential for several Morrow CO2 floods in the Oklahoma and Texas panhandles. Prior to that, Ms. Bryant held positions as a production and reservoir engineer with various firms including Amoco Production Company in Denver, Colorado. Ms. Bryant graduated from the University of Tulsa in 1980 with a Bachelor of Science degree in Petroleum Engineering.
Terry L. Toole—Director—Terry L. Toole, C.P.A. was appointed to serve as a member of the board of directors of our general partner in October 2012. Mr. Toole served as a director of New Source Energy from January 2012 until January 2013. Mr. Toole serves on the conflicts committee of the board of directors of our general partner. Mr. Toole retired as a partner of Finley & Cook, PLLC, on November 1, 2010, where he had been employed since 1976. He has significant accounting experience with companies in the oil and natural gas industry, including several publicly traded exploration and production companies and drilling funds. At the time of Mr. Toole’s retirement from Finley & Cook, he chaired the firm’s audit and oil and gas accounting departments. Mr. Toole received a Bachelor of Science degree in Business Administration (concentration in Economics) from Fort Hays State University in Hays, Kansas in 1966 and a Master’s degree in Business Administration (concentration in Accounting) in 1968 from West Texas A&M University in Canyon, Texas. He has been a Certified Public Accountant since 1970 and is a member of both the Oklahoma Society of Certified Public Accountants and the American Institute of Certified Public Accountants. We believe Mr. Toole’s expertise as a Certified Public Accountant and his extensive knowledge relating to auditing and accounting matters pertinent to the oil and natural gas industry provide important experience to the board of directors.
V. Bruce Thompson—Director—Mr. V. Bruce Thompson was appointed to serve as a member of the board of directors of our general partner in October 2012. Mr. Thompson served as general counsel of New Source Energy from August 2011 to August 2012 and has served as secretary of New Source Energy since August 2011. Mr. Thompson also serves as President of The American Exploration & Production Council (AXPC), a Washington, D.C.-based trade association whose membership is composed of 31 of America’s leading independent oil and natural gas exploration and production companies, a position he has held since October 2008. From March 2007 to April 2008, Mr. Thompson served as senior vice president and general counsel of SandRidge Energy, Inc. (NYSE: SD). Additionally, from August 2003 to March 2007, Mr. Thompson served as senior counsel with Brownstein Hyatt Farber Schreck in the firm’s Washington, D.C. and Denver offices. Previously, Mr. Thompson served as senior vice president and general counsel of Forest Oil Corporation (NYSE: FST). Mr. Thompson also served as chief of staff for then Congressman, now U.S. Senator, James Inhofe. Mr. Thompson graduated from the University of Pennsylvania’s Wharton School of Business with a Bachelor of Science degree in Economics with an emphasis on corporate finance in 1969 and received his Juris Doctorate from the University of Tulsa’s College of Law in 1974. We believe Mr. Thompson’s previous experience as the general counsel of a public company provides him with a high level of technical expertise in reviewing transactions and agreements and addressing the myriad legal issues to be presented to the board of directors.
Phil Albert—Director—Mr. Albert was appointed to serve as a member of the board of directors of our general partner in October 2012. Mr. Albert joined New Dominion in 2005 as Executive Vice President. In this position, Mr. Albert oversees operations for New Dominion, including fiscal and budgetary policies, personnel management, and has complete responsibility for strategic initiatives and investments. Before joining New Dominion in 2005, he worked at JEM Engineering in Tulsa for 21 years, serving in many leadership positions, including Controller, Treasurer, and Chief Financial Officer and finally President and Chief Operating Officer. Previously, he was an accountant and auditor for the consulting firm of Peat Marwick Mitchell, now known as KPMG. In addition to his responsibilities at New Dominion, he serves as President of Pelco Structural, LLC., a manufacturer of infrastructure products in Claremore, Oklahoma. He is a graduate of Oklahoma Baptist University in 1981
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with a magna cum laude degree in accounting. Mr. Albert currently serves as member on Claremore Chamber of Commerce Board. Mr. Albert is the brother-in-law of Mr. Chernicky. Mr. Albert’s knowledge relating to auditing and accounting matters pertinent to the oil and natural gas industry provides important experience to the board of directors.
John A. Raber—Director—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. 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 COO 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 BS in Civil Engineering and has also attended Stanford University’s Executive Business School. The board of directors concluded that Mr. Raber’s knowledge of the midstream business and business development within the energy sector qualifies him to serve as a director.
Charles Lee Reynolds III—Director—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. Mr. Reynolds is uniquely qualified to serve as a director because of his knowledge and prior experience dealing with issues relating to risk management in the energy space.
Dikran Tourian—Director— Mr. Tourian was appointed to serve as a member of the board of directors of our general partner in February 2014 pursuant to the terms of a director designation agreement dated November 12, 2013 by and among the Partnership, the General Partner, Deylau and Signature Investments, LLC, an Oklahoma limited liability company wholly owned by Mr. Tourian. Mr. Tourian has served as President of the Oilfield Services & Midstream Division of the Partnership since November 2013. Prior to joining the Partnership, Mr. Tourian was the co-founder and President of MCE, LP, a Delaware limited partnership acquired by the Partnership pursuant to the MCE Acquisition. Since 2000, Mr. Tourian has founded and sold numerous businesses, including a sale of PrimaTech Medical Systems to Compass Diversified Holdings (NYSE: CODI) 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. The board of directors of the general partner concluded that Mr. Tourian’s experience with mergers and acquisitions and his background in the oilfield services industry qualified him to serve as a director.
Committees of the Board of Directors
Audit Committee
Rules implemented by the NYSE and SEC require our general partner to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to certain transitional relief during the one-year period following the completion of our IPO. Currently, the audit committee is comprised of Messrs. Toole, the audit committee chairman, Raber and Reynolds. 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 of directors 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
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our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee.
Conflicts Committee
Messrs. Terry L. Toole, John A. Raber and Charles Reynolds comprise our conflicts committee. The conflicts committee will determine if the resolution of any conflict of interest referred to it by our general partner is in the best interests of our partnership. Any matters approved by the conflicts committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who beneficially own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act to file certain reports with the SEC and NYSE concerning beneficial ownership of such securities.
Based solely on a review of the copies of reports on Form 3, 4 and 5 and amendments thereto furnished to us and written representations from the executive officers and directors of New Source Energy GP, LLC, we believe that during the year ended December 31, 2013 the officers and directors of New Source Energy GP, LLC and beneficial owners of more than 10% of our equity securities registered pursuant to Section 12 were in compliance with the applicable requirements of Section 16(a), with the exception of a late Form 3 filed by Ms. Bryant.
Corporate Governance
The board of directors of our general partner has adopted a Financial Code of Ethics that applies to the chief executive officer, chief financial officer, controller, treasurer and all other persons performing similar functions on behalf of our general partner and us. Amendments to or waivers from the Financial Code of Ethics will be disclosed in accordance with the rules and regulations of the SEC and the listing requirements of the NYSE. The Board has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and its affiliates and us.
We make available free of charge, within the “Corporate Governance” section of our website at http://www.newsource.com/Investors/Corporate-Governance/default.aspx, the Financial Code of Ethics, the Corporate Governance Guidelines and the Code of Business Conduct and Ethics. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.
Communications with Directors
The board of directors of our general partner 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. Our Corporate Secretary 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 general partner’s Corporate Secretary 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 of directors of our general partner 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.
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Meetings of Non-Management Directors
The non-management directors of our general partner generally hold regularly scheduled meetings in executive session immediately following each regularly scheduled Board meeting. At least once a year, these executive sessions include only directors who qualify as independent under the listing requirements of the New York Stock Exchange. A lead director is designated by the board of directors of our general partner to preside at these meetings. The lead director is responsible for preparing an agenda for the meetings of the non-management or independent directors in executive session. Our current lead director is V. Bruce Thompson.
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| ITEM 11. | EXECUTIVE COMPENSATION |
Compensation Overview
Executive Summary
We and our general partner were formed by New Source Energy in October 2012. We do not currently employ any of the persons responsible for managing our business. All of the executive officers that are responsible for managing our day-to-day affairs are also current executive officers of our parent New Source Energy.
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 of December 31, 2013, as well as limited narrative disclosures. Further, our reporting obligations extend only to the individual serving as our chief executive officer and our two other most highly compensated executive officers. The individuals that are considered to be our “named executive officers” and which are also “named executive officers” at New Source Energy are as follows:
| • | Kristian B. Kos - Chief Executive Officer and President |
| • | Richard D. Finley - Chief Financial Officer; and |
| • | David J. Chernicky - Senior Geologist |
| • | Carol T. Bryant - Senior Engineer |
Summary Compensation Table
| Name and Principal Position | Year | Stock Awards ($)(1) | Total ($)(2) | ||||||
| Kristian B. Kos | 2013 | 3,125,738 | $ | 3,125,738 | |||||
| Chief Executive Officer and President | |||||||||
| Richard D. Finley | 2013 | 467,400 | $ | 467,400 | |||||
| Chief Financial Officer | |||||||||
| David J. Chernicky | 2013 | 3,125,738 | $ | 3,125,738 | |||||
| Senior Geologist | |||||||||
| Carol T. Bryant | 2013 | 467,400 | 467,400 | ||||||
| Senior Engineer | |||||||||
_______________________
| (1) | Amounts in this column reflect the grant date fair value of the LTIP awards granted to our named executive officers during the 2013 year, calculated in accordance with ASC FASB Topic 718, disregarding any risk of forfeiture. See Note 14 to our Consolidated Financial Statements for a more detailed discussion of the assumptions used to calculate the value of these awards. |
| (2) | Amounts in this column reflect only the value of the LTIP awards that we granted in the 2013 year. New Source Energy was responsible for all other compensation that may have been paid to our named executive officers for the 2013 year, and we paid a quarterly fee to New Source Energy for the named executive officers services, as further described below. |
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Compensation for the 2013 Fiscal Year
During the year ended December 31, 2013, our named executive officers remained directly employed by New Source Energy and it was New Source Energy that made all compensation decisions and provided compensation payments to our named executive officers. Due to the structure of our omnibus agreement (detailed below), neither we nor New Source Energy considered the compensation that New Source Energy provided to the named executive officers to have been allocated to us at any time during the 2013 year.
Although New Source Energy did not allocate compensation costs to us in 2013, and we did not separately compensate our named executive officers for their services to us during 2013, our general partner appreciated that the efforts of our named executive officers during our IPO and immediately thereafter were an integral part of the success of our IPO. In recognition of those efforts, following the completion of our IPO, our general partner granted our named executive officers equity-based compensation awards pursuant to the New Source Energy Partners L.P. Long Term Incentive Plan, or “LTIP,” during February 2013, as more fully discussed below. 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 in the 2013 year.
Omnibus Agreement and Our Future Compensation Arrangements with New Source Energy
In connection with the closing of our IPO in February 2013, we entered into an omnibus agreement with New Source Energy, pursuant to which, among other things, New Source Energy will provide management and administrative services for us and our general partner. During the 2013 year, we paid a set quarterly fee to New Source Energy for such services that was not impacted by the amount of time that our named executive officers spent in performing services for us or for New Source Energy. Following the 2013 year, however, we will reimburse our general partner on a quarterly basis for actual expenses that it incurs in its performance under the omnibus agreement and for any payments that our general partner makes to New Source Energy.
Responsibility and authority for compensation-related decisions for executive officers and other personnel that are employed by New Source Energy will continue to reside with New Source Energy, other than decisions related directly to our LTIP. New Source Energy has the ultimate decision-making authority with respect to the total compensation of its employees, including the individuals that serve as our named executive officers, and (subject to the terms of the omnibus agreement) with respect to the portion of compensation that may become allocated to us in the future. Any such compensation decisions will not be subject to any approval by the board of directors of our general partner. Although we will bear the responsibility of providing the required fees to New Source Energy pursuant to the omnibus agreement for the compensation and benefits provided to the New Source Energy employees who provide services to us, we will have no control over such costs. All decisions regarding awards under the LTIP will be made by our general partner’s board of directors or its delegates.
The employee compensation costs that are covered under the omnibus agreement do not include any costs associated with equity-based compensation awards that we may grant to individuals pursuant to our LTIP, or any cash compensation that we choose to pay to any New Source Energy employee directly and any such compensation may be charged to NSLP accordingly. The LTIP was adopted by our general partner’s board of directors on January 30, 2013, and all decisions regarding awards under the LTIP will be made by our general partner’s board of directors or its delegates. Responsibility and authority for compensation-related decisions for personnel employed directly by our general partner, if any, will also reside with our general partner.
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Outstanding Equity Awards at 2013 Fiscal Year End
| 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 | 3,125,738 | |||
| Richard D. Finley | 20,000 | 467,400 | |||
| David J. Chernicky | 133,750 | 3,125,738 | |||
| Carol T. Bryant | 20,000 | 467,400 | |||
___________________
| (1) | The restricted units reflected in this table will vest on the date at which the subordination period ends, but see the discussion below for potential treatment of the awards upon a termination of employment or a change in control. |
| (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, 2013 of $23.37. |
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 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 or us of all or substantially all of its 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; (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.
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DIRECTOR COMPENSATION
Each of the non-employee members of the board of directors of our general partner will receive an annual retainer of $100,000, which may be paid in the form of cash, equity or some combination of cash and equity, at our general partner’s discretion. In the event that our general partner chooses to pay the annual retainer in the form of equity, such common units will be granted pursuant to the LTIP. The non-employee directors will also be compensated for their time spent serving on committees or for completing special projects, pursuant to an hourly rate fee arrangement. For the 2013 year, that hourly rate was $200.
In addition to the compensation arrangement described above, the non-employee directors will also be eligible to receive awards pursuant to the LTIP from time to time, at our general partner’s discretion. Terry L. Toole, V. Bruce Thompson and Phil Albert also received restricted unit awards in February 2013, in recognition for their efforts associated with our IPO, in the amount of 5,000, 5,000 and 12,500 units, respectively. The terms and conditions of these Restricted Unit Awards are substantially similar to those provided to our named executive officers and described above.
Director Compensation Table:
| Name and Principal Position | Year | Fees earned or paid in cash ($) | Stock Awards ($)(*) | Total ($) | ||||||||||
| Terry L. Toole | 2013 | $ | 89,747 | $ | 99,250 | $ | 188,997 | |||||||
| V. Bruce Thompson | 2013 | $ | 88,022 | $ | 99,250 | $ | 187,272 | |||||||
| Phil Albert | 2013 | $ | 60,222 | $ | 248,125 | $ | 308,347 | |||||||
| John A. Raber | 2013 | $ | 48,833 | $ | — | $ | 48,833 | |||||||
____________________
| (*) | Amounts in this column reflect the grant date fair value of the LTIP awards granted to our directors during the 2013 year, calculated in accordance with ASC FASB Topic 718, disregarding any risk of forfeiture. See Note 14 to our Consolidated Financial Statements for a more detailed discussion of the assumptions used to calculate the value of these awards. As of December 31, 2013, our directors held the following number of outstanding equity awards under the LTIP: Mr. Toole, 5,000; Mr. Thompson, 5,000 and Mr. Albert, 12,500. |
Compensation Committee Interlocks and Insider Participation
As a limited partnership, we are not required by the NYSE to establish a compensation committee. Although the board of directors of our general partner does not currently intend to establish a compensation committee, it may do so in the future.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS |
As of March 31, 2014, the following table sets forth the beneficial ownership of our common and subordinated units that are owned by:
| • | each person who then will beneficially own more than 5% of the then outstanding common units; |
| • | each director of our general partner; |
| • | each named executive officer of our general partner; and |
| • | all directors and executive officers of our general partner as a group. |
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Unless otherwise noted, the mailing address of each person or entity named below is 914 North Broadway, Suite 230, Oklahoma City, Oklahoma 73102.
| Name of Beneficial Owner(1) | Common Units to be Beneficially Owned | Percentage of Common Units to be Beneficially Owned | Subordinated Units to be Beneficially Owned | Percentage of Subordinated Units to be Beneficially Owned | Percentage of Total Common and Subordinated Units to be Beneficially Owned | ||||||||||
| New Source Energy Corporation (2) | 1,125,500 | 11.2 | % | 2,205,000 | 100 | % | 27.1 | % | |||||||
| David J. Chernicky (2) | 133,750 | 1.3 | % | — | — | % | 1.1 | % | |||||||
| Kristian B. Kos (3) | 133,750 | 1.3 | % | — | — | % | 1.1 | % | |||||||
| Richard D. Finley (7) | 20,000 | *% | — | — | % | *% | |||||||||
| Carol T. Bryant (7) | 20,000 | *% | — | — | % | *% | |||||||||
| Terry L. Toole (7) | 5,000 | *% | — | — | % | *% | |||||||||
| V. Bruce Thompson (7) | 5,000 | *% | — | — | % | *% | |||||||||
| Phil Albert (7) | 12,500 | *% | — | — | % | *% | |||||||||
| John A. Raber | 300 | *% | — | — | % | *% | |||||||||
| Charles Lee Reynolds III | — | — | % | — | — | % | — | % | |||||||
| Signature Investments, LLC (4) | 665,939 | 6.6 | % | — | — | % | 5.4 | % | |||||||
| Dikran Tourian (4) | 665,939 | 6.6 | % | — | — | % | 5.4 | % | |||||||
| Goldman Sachs Asset Management (5) | 913,821 | 9.1 | % | — | — | % | 7.4 | % | |||||||
| Scintilla, LLC (2) | 1,390,545 | 13.8 | % | — | — | % | 11.3 | % | |||||||
| CEU Paradigm, LLC (6) | 488,667 | 4.8 | % | — | — | % | 4.0 | % | |||||||
| Deylau, LLC (3) | 665,939 | 6.6 | % | — | — | % | 5.4 | % | |||||||
| All executive officers and directors as a group (ten persons) (2) | 3,718,662 | 36.9 | % | 2,205,000 | 100 | % | 48.2 | % | |||||||
* Represents less than 1% of the outstanding common units.
| (1) | Based upon an aggregate of 10,088,245 shares issued and outstanding as of March 31, 2014. |
| (2) | David J. Chernicky is the Chairman and controlling shareholder of New Source Energy and may be deemed to beneficially own the units held by New Source Energy Corporation. In addition, David J. Chernicky indirectly owns 1,390,545 common units held by Scintilla. David J. Chernicky owns 100% of the outstanding membership interests in Scintilla. David J. Chernicky disclaims beneficial ownership of units held by New Source Energy in excess of his pecuniary interest in New Source Energy. Common units beneficially owned also include 133,750 units held under the Partnership's long-term incentive plan. |
| (3) | Kristian B. Kos is the sole member of Deylau, LLC, a Delaware limited liability company (“Deylau”), and as such may be deemed to beneficially own all of the units held by Deylau. |
| (4) | Dikran Tourian is the sole member and manager of Signature Investments, LLC, an Oklahoma limited liability company (“Signature”), and as such may be deemed to beneficially own all of the units held by Signature. |
| (5) | According to a Schedule 13G filed on February 10, 2014 by Goldman Asset Management, it has sole voting and dispositive power over none of these units and shared voting and dispositive power over all of the units. The address of Goldman Sachs Asset Management is 200 West Street, New York, New York 10282. |
| (6) | According to a Schedule 13G filed on February 10, 2014 by CEU Paradigm, LLC, it has sole voting and dispositive power over all of these units. The address of CEU Paradigm, LLC is 100 Constellation Way, Suite 500C, Baltimore, Maryland 21202. |
| (7) | Common units beneficially owned represent units held under the Partnership's long-term incentive plan. |
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Securities Authorized for Issuance Under Equity Compensation Plans
As discussed above, prior to the completion of our IPO, on January 30, 2013, the board of directors of our general partner adopted the LTIP for employees, officers, consultants and directors of our general partner and any of its affiliates, including New Source Energy, who perform services for us. The purpose of the LTIP is to provide a means to attract and retain individuals who will provide services to us by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. Upon the closing of the IPO, on February 13, 2013, the board of directors of our general partner awarded a total of 367,500 restricted units to certain officers and directors of our general partner. No equity compensation plans have been approved by our unitholders.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
Using ownership information as of March 31, 2014, the Partnership is controlled by the Partnership's general partner, which is owned 69.4% by the Partnership's President and Chief Executive Officer, Kristian Kos, and 25.0% by the Partnership's Chairman and Senior Geologist, David J. Chernicky. Kristian B. Kos owns approximately 7.9% of the Partnership's outstanding common units, including units owned through the Partnership's long-term incentive plan, and units owned through through Deylau, LLC, an entity he controls. David J. Chernicky owns approximately 26.3% of the Partnership's outstanding common units, including units owned through the Partnership's long-term incentive plan, and units owned through New Source Energy and Scintilla, entities which he controls. In addition, David J. Chernicky owns 100% of the 2,205,000 subordinated units through New Source Energy. David J. Chernicky owns all of the membership interests in the Partnership's operator, New Dominion.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, were not the result of arm’s-length negotiations.
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Formation Stage
The consideration received by our general partner and New Source Energy prior to or in connection with our IPO | Ÿ | 777,500 common units; |
| Ÿ | 2,205,000 subordinated units; | |
| Ÿ | 155,102 general partner units; | |
| Ÿ | all of our incentive distribution rights; | |
| Ÿ | a $25.0 million note payable; and | |
| Ÿ | approximately $15.8 million in cash. | |
The consideration received by New Source Energy in connection with our acquisition of additional properties | Ÿ | 348,000 common units. |
| Operational Stage | ||
Distributions of available cash to our general partner and its affiliates | We will generally make cash distributions of 100% to our unitholders and our general partner, in accordance with their percentage interests . In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to a maximum of 23.0% of the distributions above the highest target distribution level, | |
Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $0.3 million on its general partner units and New Source Energy would receive an annual distribution of approximately $6.6 million on its common units and subordinated units. | ||
| Payments to our general partner and its affiliates | Pursuant to our omnibus agreement, New Source Energy provided management and administrative services for us and our general partner through December 31, 2013, for which we paid New Source Energy a quarterly fee of $675,000 for the provision of such services. After December 31, 2013, in lieu of the quarterly fee, we will reimburse our general partner for the actual direct and indirect expenses it incurs in its performance. We are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit. | |
| Withdrawal or removal of our general partner | If our general partner is removed under circumstances where cause exists or withdraws where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the departing general partner’s general partner interest in us and the incentive distribution rights for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the departing general partner’s general partner interest in us and its incentive distribution rights for their fair market value or to convert such interests into common units. | |
| Liquidation | Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. | |
Related Party Agreements
Golden Lane Participation Agreement
At the closing of our IPO, we became a party to the Golden Lane Participation Agreement. The other parties to the Golden Lane Participation Agreement include New Dominion, as operator, New Source Energy and Scintilla, as continuing working interest owners, and a number of unaffiliated entities that also own working interests in the Golden Lane field.
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The Golden Lane Participation Agreement controls the development and operation of the Golden Lane field and provides New Dominion, as operator, with authority to control the development and operation of the field. New Dominion’s control rights are subject to its agreement to use its commercially reasonable efforts to conduct its operations in a manner consistent with the development agreement described below. New Dominion also is empowered to acquire additional leasehold within the Golden Lane field for the account of the working interest owners in exchange for a turnkey fee per net acre acquired. This turnkey fee is currently $300 per net acre acquired and may be increased by New Dominion from time to time in the event of an increase in prevailing leasehold acquisition costs. The Golden Lane Participation Agreement permits New Dominion to hold record title to any undeveloped leasehold within the Golden Lane area of mutual interest that it acquires in the future for the benefit of the parties to the Golden Lane Participation Agreement until such time as development of the applicable leasehold commences. Generally, New Dominion may defer our obligation to pay our proportionate share of the cost of this leasehold for a turnkey acreage fee then applicable under the Golden Lane Participation Agreement until development has commenced. Although New Dominion would hold record title to any such undeveloped leasehold, the Golden Lane Participation Agreement requires the assignment to us of the leasehold when development commences, and it is this right on which we rely in connection with estimating any proved undeveloped reserves associated with such acreage hereafter acquired by New Dominion for our benefit in our future reserve reports. Each party to the Golden Lane Participation Agreement has committed to participate in future wells proposed by the operator for its proportionate share of the costs associated with such wells. The parties also have agreed to pay New Dominion their proportionate shares of an initial connection charge of $300,000 per well in the Golden Lane field, subject to increase in certain circumstances, for connection and access to its saltwater disposal infrastructure within the Golden Lane field and also to pay New Dominion their proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.
In the event that New Dominion acquires additional leasehold acreage for the benefit of the parties to the Golden Lane Participation Agreement (including by means of forced pooling) and subsequently commences development, New Dominion will assign record title to the other parties to the Golden Lane Participation Agreement in their proportionate share. In connection with any such assignment, New Dominion will retain an overriding royalty interest in an amount equal to 20.0% less any existing royalties or overriding royalty interests that burden the applicable lease; however, if existing royalties and overriding royalty interests exceed 20.0% in the aggregate for a particular lease, New Dominion will not retain an overriding royalty interest with respect to such lease. Additionally, if New Dominion is unable to acquire the entirety of the oil and gas leasehold estate under the drilling and spacing unit for a proposed well, then each party’s share of the ownership within such drilling and spacing unit shall be proportionately reduced in any assignment pursuant to the Golden Lane Participation Agreement. Further, if New Dominion is unable to acquire all depths and formations attributable to a particular lease, then the proportionate share of each of the parties with respect to such lease included within any assignment pursuant to the Golden Lane Participation Agreement shall be limited to only those depths and formations so acquired by New Dominion.
The Golden Lane Participation Agreement requires us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. The Golden Lane Participation Agreement contains significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements, as is customary in the oil and natural gas industry. If a party declines to participate in a new well that New Dominion proposes, such party will not be eligible to participate in the next four wells in adjacent drilling and spacing units to such proposed well (unless the proposed well is in an undrilled township and range, in which case such party will not be eligible to participate in the next eight wells in adjacent drilling and spacing units to the proposed well), and such party also would be obligated to pay for its share of the applicable acquisition costs associated with the leasehold interests underlying the proposed new well even though it has elected not to participate in the well and the associated costs themselves. In addition, if a party declines to participate in a new well that New Dominion proposes, such party will relinquish its interest in the new well and its share of production from the new well until such time at which the proceeds from such relinquished interest paid to the working interest owners that elected to participate in the new well reach specified aggregate thresholds intended to compensate the parties for the election not to participate. The Golden Lane Participation Agreement requires us to contribute our entire share of estimated drilling and completion costs within 30 days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs later.
In return for serving as the operator of the Golden Lane field, New Dominion is entitled to receive reimbursement for costs allocable to the wells subject to the Golden Lane Participation Agreement, including allocable shares of its employees and certain other general and administrative expenses, under joint account procedures common in the oil and natural gas industry. We generally are required to pay our proportionate share of these ongoing costs associated with the operation of our wells on a monthly basis and within 30 days of the date of New Dominion’s invoice.
Luther Joint Operating Agreement
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In connection with our acquisition of certain of the properties in the March Acquisition from New Source Energy and Scintilla, we succeeded to those parties’ rights and obligations under a joint operating agreement governing the Luther field, which we refer to as the “Luther JOA.” New Dominion is the 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 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 and natural gas, 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 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 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 operator of the Luther field, 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 operator’s invoice.
Eight East Participation Agreement
In connection with the May Acquisition from New Source Energy and the July Acquisition from Scintilla, 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 operator, and unaffiliated third parties that also own working interests in the Eight East area of mutual interest.
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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 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 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 for wells in which we elect to participate within 30 days of a new well notice from the operator or at least five days prior to the spud date for the new well, depending on which event occurs earlier.
In return for serving as the 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.
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 operator, and an unaffiliated third party that also owns a working interest in the Southern Dome field.
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The Southern Dome Participation Agreement controls the development and operation of the Southern Dome field and provides New Dominion, as 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 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 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 operator or 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 operator when such costs exceed $100,000.
In return for serving as the 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.
Development Agreement
We are party to a development agreement with the New Source Group with respect to the development of the IPO Properties. Pursuant to the development agreement, during each of our fiscal years ending December 31, 2013 through December 31, 2016, we have agreed to maintain an annual maintenance drilling budget averaging no less than $8.2 million to drill certain of our proved undeveloped locations and maintain our producing wells. In connection with our entry into the
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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.”
Additionally, beginning with the first quarter of 2014 and continuing through the fourth quarter of 2016, if our average production declines below 3,200 Boe/d for any preceding four quarter period, then holders of our subordinated units will not be entitled to receive the quarterly distributions otherwise payable on our subordinated units for such quarter. We expect that any funds not distributed to holders of our subordinated units will be reserved by the board of directors of our general partner for use in growing our production.
While we have committed to establishing a maintenance drilling budget averaging no less than $8.2 million annually from 2013 through 2016 pursuant to the development agreement, we anticipate that our general partner will propose, not less than annually, additional growth capital expenditures and related drilling and development projects to grow our resources and production over time. We expect this growth to come through drilling additional proved undeveloped properties, increasing our working interests in wells through forced pooling and acquiring properties from both New Source Energy and third parties. The amount and timing of these growth capital expenditures will depend on both the amount of capital we have available to fund such expenditures as well as the success of our drilling program.
Pursuant to the development agreement, our general partner will, at least annually and likely more frequently, at its discretion, determine our maintenance drilling budget. Our general partner will also have the right to propose which wells are drilled based on our maintenance drilling budget. Under the development agreement, New Dominion will use its commercially reasonable best efforts to (i) conduct its operations such that the Partnership’s proportionate share of capital expenses that we would consider maintenance capital under the Golden Lane Participation Agreement is equal to the annual maintenance drilling budget set by our general partner and (ii) cause the wells drilled pursuant to the Golden Lane Participation Agreement to be consistent with the maintenance drilling schedule proposed by our general partner. Our general partner will also have the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.
Omnibus Agreement
We and our general partner were parties to an omnibus agreement with New Source Energy, pursuant to which, among other things, New Source Energy provided management and administrative services for us and our general partner through December 31, 2013, for which we paid New Source Energy a quarterly fee of $675,000 for the provision of such services. After December 31, 2013, in lieu of the quarterly fee, we will reimburse our general partner for the actual direct and indirect expenses it incurs in its performance.
We are responsible for the costs of any equity-based compensation awarded to our management or the board of directors of our general partner. We are also responsible for all acquisition costs for acquisitions evaluated or completed for our benefit.
Contribution, Conveyance and Assumption Agreement
In connection with the closing of our IPO, we and our general partner entered into a contribution, conveyance and assumption agreement with New Source Energy that effects, among other things, portions of the formation transactions, including the transfer of the IPO Properties to us and the use of the net proceeds of the IPO. All of the transaction expenses incurred in connection with these transactions were paid from proceeds of our IPO. We hold title to the assets and interests acquired through these agreements and also entered into an omnibus agreement, through December 31, 2013, with New Source Energy related to these assets and interests as discussed above.
Director Indemnification Arrangements
We and our general partner entered into indemnification agreements with our directors which will generally indemnify our directors to the fullest extent permitted by law. Our general partner maintains director and officer liability insurance for the benefit of its directors and officers.
March Contribution Agreements
On March 29, 2013, we completed the acquisition of the March Acquired Properties, with an effective date of March 1, 2013, from New Source Energy, Scintilla, and W.K. Chernicky, LLC, an Oklahoma limited liability company (“WKC” and, collectively with NSEC and Scintilla, the “Contributors”) pursuant to Contribution Agreements (the “March Contribution Agreements”) by and between us and each of the Contributors. As consideration for the contributed assets, we issued an
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aggregate of 1,378,500 common units to the Contributors. The March Contribution Agreements contain representations and warranties, covenants and indemnification provisions that are typical for transactions of this nature. The properties are located in the Golden Lane field, where a majority of our current oil and gas assets are located, and in the Luther Field, which is adjacent to the Golden Lane field. These properties had estimated proved reserves of 3.2 MMBoe as of December 31, 2013, of which 60% were proved developed, 6% were oil, 64% were NGLs and 30% were gas.
May Conveyance Agreement
On May 31, 2013, we completed the acquisition of the May Acquired Properties, with an effective date of May 1, 2013, from New Source Energy pursuant to an Assignment, Bill of Sale and Conveyance by and between us and New Source Energy. As consideration for the May Acquired Properties, we paid a total of approximately $8.1 million in cash to New Source Energy after purchase price adjustments, representing a reimbursement of the costs incurred by New Source Energy to acquire and develop these properties through May 22, 2013. These properties are located in the Golden Lane field and had estimated proved reserves of 820 MBoe as of December 31, 2013, of which 1% were oil, 63% were NGLs and 35% were gas.
July Purchase and Sale Agreement
On July 23, 2013, we completed an acquisition of a 10% working interest in certain oil and gas properties located in Oklahoma, with an effective date of May 1, 2013, from Scintilla pursuant to a Purchase and Sale Agreement dated such date. As consideration for the working interests, we paid a total of $4.9 million in cash to Scintilla after purchase price adjustments. The properties are located in the Golden Lane field. Based on internal estimates, the properties had estimated proved reserved of 266.5 MBoe as of December 31, 2013, of which 7% were oil and 60% were NGLs and 33% were gas.
October Contribution Agreement
On October 4, 2013, we completed the acquisition of the Southern Dome Acquired Properties pursuant to a Contribution Agreement (the “October Contribution Agreement”) by and between us and Scintilla, with an effective date of August 1, 2013. The contributed assets generated average daily production of 383.5 Boe/d during the period between May 1, 2013 and July 31, 2013 (the “Current Production Average”), of which the commodity breakdown was 51% natural gas, 34% oil and 15% NGLs. Based on our working interest, we acquired estimated proved reserves of 1.2 MMBoe as of December 31, 2013, of which 42% were oil, 13% were NGLs and 45% were gas.
As consideration for the working interests, we paid $5 million in cash to Scintilla at closing and issued 414,045 common units to Scintilla in November 2013, valued at $20.34 per common unit, which represents the average high and low trading prices for the Partnership’s common units on the New York Stock Exchange for the five trading days immediately preceding the closing of the acquisition. We also agreed to provide additional consideration to Scintilla in November 2014 if the production attributable to the contributed assets for the nine-month period ending September 30, 2014 exceeds the Current Production Average. As detailed in the Southern Dome Contribution Agreement, the amount of any such additional consideration will be calculated as the acquisition value of the production increase (applying the same valuation methodology as was used to determine the initial consideration with respect to the Current Production Average) less (i) the 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 that were not producing in paying quantities as of the effective date of the acquisition. We may satisfy any such additional consideration in cash, common units, or a combination thereof at our discretion. The Southern Dome Contribution Agreement also contains representations and warranties, covenants and indemnification provisions that are typical for transactions of this nature.
MCE Contribution Agreement
On November 12, 2013, we entered into the MCE Contribution Agreement with certain individuals, including Kristian B. Kos (collectively, the “MCE Owners”), and MCE, LLC, a Delaware limited liability company (“MCE LLC” and, together with the MCE Owners, the “MCE Parties”).
Pursuant to the MCE Contribution Agreement, the MCE Parties contributed (the “Contribution”) all of the equity interests of the MCE Entities for approximately $43.6 million in total initial consideration, which consisted of approximately $3.8 million in cash and 1,847,265 common units, valued using a volume weighted average trading price for the period between August 21, 2013 and November 11, 2013 of $22.64 per common unit. We also agreed to issue 99,768 common units, valued at $22.64 per common unit to certain employees of the MCE Entities under our long-term incentive plan, for aggregate total consideration of approximately $48.9 million. The MCE Owners are also entitled under the MCE Contribution Agreement to receive additional common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of the
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MCE Entities for the trailing nine month period ended March 31, 2015, less certain adjustments, as set forth in the MCE Contribution Agreement (the “Earn-out Common Units”), which is subject to a $120 million cap.
In addition to the aggregate total consideration paid by us for the MCE Entities, certain of the MCE Owners retained Class B Units in MCE LP following the Contribution, which entitle the holders to receive incentive distributions of cash distributed by MCE LP above specified thresholds in increasing amounts, up to a maximum of 50% at the highest level of incentive distribution. For more information regarding the Class B Units of MCE LP, see “MCE Partnership Agreement.”
The MCE Contribution Agreement also contains representations, warranties, covenants and indemnification provisions that are typical for transactions of this nature. The effective date of the acquisition of the MCE Entities is November 1, 2013.
Option Agreement
On November 12, 2013, in connection with the MCE Contribution Agreement, we entered into an option agreement (the “Option Agreement”) with Kristian B. Kos and certain other MCE Owners (collectively, the “Option Grantors”), and Torus Energy Services, LLC, an Oklahoma limited liability company (“Torus” and together with the Option Grantors, the “Option Parties”). Torus owns MidCentral Completion Services, LLC, an Oklahoma limited liability company (“MidCentral Services”). MidCentral Services is an oilfield completion services company complementary to the business operations of MCE LP.
Pursuant to the Option Agreement, the Option Parties granted us the right to require Torus to cause all of the outstanding limited liability company interests (the “Option Interest”) in MidCentral Services to be contributed to us and assigned, transferred and delivered to MCE LP (the “Option”). We may exercise the Option by written notice at any time within 60 days of receiving a favorable Private Letter Ruling from the United States Internal Revenue Service regarding the gross income of MidCentral Services. If we do not exercise the Option, the Option Agreement will automatically terminate on the earlier of (i) the day following the end of such 60-day period and (ii) May 31, 2015. If we exercise the Option, the parties have agreed to negotiate in good faith a contribution or similar agreement (the “MidCentral Services Contribution Agreement”) related to the conveyance of the Option Interest, with terms and provisions substantially similar to those contained in the MCE Contribution Agreement, including the valuation methodology for the initial consideration and earn-out amounts. The Option Agreement also contains representations, warranties and covenants that are typical for transactions of this nature.
MCE Partnership Agreement
On November 12, 2013, in connection with the contribution of the MCE Entities, the agreement of limited partnership of MCE LP was amended and restated to, among other things, create Class A Units and Class B Units of MCE LP (as so amended and restated, the “MCE Partnership Agreement”). Deylau, LLC, a Delaware limited liability company wholly-owned by Kristian B. Kos (“Deylau”) and Signature Investments, LLC, an Oklahoma limited liability company wholly-owned by Dikran Tourian (“Signature”), the President of MCE GP and one of the MCE Owners (“Dikran Tourian”), retained the Class B Units, which entitle the holders to receive incentive distributions of cash distributed by MCE LP above specified thresholds in increasing amounts, up to a maximum of 50% at the highest level of incentive distribution. We currently hold all of the Class A Units, which are entitled to all cash distributed by MCE LP other than the incentive distributions made in respect of the Class B Units.
Additionally, at any time when MCE LP has made cash distributions to the holders of the Class B Units at the highest level of incentive distribution for each of the four most recently completed fiscal quarters, the holders of the Class B Units have the right under the MCE Partnership Agreement to elect (a “Reset Election”) to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to “reset,” at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments on the Class B Units would be set. In exchange for resetting the minimum quarterly distribution and target distribution levels, the holders of the Class B Units would receive consideration in an amount based on a predetermined formula that takes into account the “cash parity” value of the recent cash distributions related to the Class B Units prior to the reset event. Upon making a Reset Election, the holders of the Class B Units are entitled to consideration equal to the quotient obtained by dividing (i) the lesser of (a) the average distribution per unit received on the Class B Units for the two full quarters preceding the Reset Election and (b) the distribution per unit received on the Class B Units for the quarter preceding the Reset Election, and (ii) the most recent quarterly distribution on the common units, multiplied by the volume weighted average trading price of the common units for the twenty-day period prior to the Reset Election. We may satisfy this consideration requirement in cash, newly issued common units or a combination thereof in its sole discretion.
Registration Rights Agreement
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On November 12, 2013, in connection with the MCE Contribution Agreement, we and the MCE Owners entered into a Registration Rights Agreement (the “Registration Rights Agreement”), which granted certain registration rights to the MCE Owners, including rights to (a) cause the Partnership to file with the Securities and Exchange Commission up to three shelf registration statements under the Securities Act for (i) resales of the common units issued to the MCE Owners under the MCE Contribution Agreement, (ii) resales of any Earn-out Common Units issued to the MCE Owners and (iii) resales of any common units issued in connection with a Reset Election by the Class B Units, and (b) participate in future underwritten public offerings of our common units.
Kristian B. Kos and Dikran Tourian (collectively, the “Demand Rights Holders”) may exercise their right to request that a shelf registration statement be filed any time on or after satisfaction of the Registration Criteria (as that term is defined in the Registration Rights Agreement). In addition, we have agreed to use commercially reasonable efforts to (a) prepare and file a shelf registration statement within 30 days of receiving a request from the Demand Rights Holders and (b) cause the shelf registration statement to be declared effective by the SEC no later than 180 days after its filing. The Registration Rights Agreement contains customary representations, warranties and covenants, and customary provisions regarding rights of indemnification between the parties with respect to certain applicable securities law liabilities.
Director Designation Agreement
On November 12, 2013, in connection with the MCE Contribution Agreement, we and our general partner entered into a Director Designation Agreement (the “Director Designation Agreement”) with Deylau and Signature (the “Designators”). Pursuant to the Director Designation Agreement, Deylau, in its capacity as the controlling member of our general partner, agreed to expand the size of the board of directors of our general partner from six to seven directors and to appoint an individual designated by the Designators to our general partner’s board of directors (the “Designated Director”). Such Designated Director will hold office until (i) his or her term expires and such Designated Director’s successor designated by the Designators has been appointed or (ii) such Designated Director’s earlier death, resignation or removal. The Designators’ designation rights terminate at such time that the Designators and their respective affiliates collectively hold fewer than 50 Class B Units.
Transactions with Directors and Officers
New Source Energy engaged Finley & Cook, PLLC to provide various accounting services during the year ended December 31, 2013. Richard Finley, our Chief Financial Officer, was an equity member of Finley & Cook, holding a 31.5% ownership interest. New Source Energy paid Finley & Cook approximately $523,000 in fees for accounting services for the year ended December 31, 2013, of which Mr. Finley’s share based on his ownership interest is approximately $165,000.
Review, Approval or Ratification of Transactions with Related Persons
We have adopted a Code of Business Conduct and Ethics that sets forth our policies for the review, approval and ratification of transactions with related persons. Pursuant to our Code of Business Conduct and Ethics, the directors of our general partner are expected to bring to the attention of the Chief Executive Officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, our general partner’s board of directors, or the conflicts committee of our general partner’s board of directors. The executive officers of our general partner are required to avoid conflicts of interest unless approved by the board of directors.
The board of directors of our general partner has a conflicts committee comprised of one independent director. Our general partner may, but is not required to, seek the approval of the conflicts committee in connection with future acquisitions from (or other transactions with) New Source Energy or any of its affiliates. In the case of any sale of equity or debt by us to New Source Energy or any of its affiliates, we anticipate that our practice will be to obtain the approval of the conflicts committee for the transaction. The conflicts committee will be entitled to hire its own financial and legal advisors in connection with any matters on which the board of directors of our general partner has sought the conflicts committee’s approval.
The New Source Group is free to offer properties to us on terms it deems acceptable, and the board of directors of our general partner (or the conflicts committee) is free to accept or reject any such offers, negotiating terms it deems acceptable to us. As a result, the board of directors of our general partner (or the conflicts committee) will decide, in its sole discretion, the appropriate value of any assets offered to us by the New Source Group. In so doing, we expect the board of directors (or the conflicts committee) will consider a number of factors in its determination of value, including, without limitation, production
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and reserve data, operating cost structure, current and projected cash flows, financing costs, the anticipated impact on distributions to our unitholders, production decline profile, commodity price outlook, reserve life, future drilling inventory and the weighting of the expected production between oil and natural gas.
We expect that the New Source Group will consider a number of the same factors considered by the board of directors of our general partner to determine the proposed price for any assets it may offer to us in future periods. In addition to these factors, given that New Source Energy is our largest unitholder following the closing of our IPO and through its interest in our incentive distribution rights, it may consider the potential positive impact on its underlying investment in us by offering properties to us at attractive purchase prices. Likewise, it may consider the potential negative impact on its underlying investment in us if we are unable to acquire additional assets on favorable terms, including the negotiated purchase price.
Director Independence
The board of directors of our general partner has reviewed the independence of our current directors and, based on this review, determined that Messrs. Toole, Raber and Reynolds 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.
| ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES |
For the years ended December 31, 2013 and 2012, the accounting fees and services (in thousands) charged by BDO USA, LLP, our independent auditors, were as follows:
| Years Ended December 31, | |||||||
| 2013 | 2012 | ||||||
| Audit fees (1) | $ | 938 | $ | 946 | |||
| Audit related fees (2) | 428 | — | |||||
| $ | 1,366 | $ | 946 | ||||
| (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. During the year ended December 31, 2012, fees associated with our IPO totaled $0.6 million. |
(2) Audit related fees represent fees to audit financial statements of acquired business. During the year ended December 31, 2013, fees associated with acquisitions totaled $0.4 million.
Audit Committee Pre-Approval Policies and Procedures
The audit committee of our general partner, on at least an annual basis, will review audit and non-audit services performed by BDO USA, LLP as well as the fees charged by BDO USA, LLP for such services. Our policy is that all audit and non-audit services must be pre-approved by the audit committee pursuant to the audit committee's pre-approval policies and procedures.
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PART IV.
| ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
| Exhibit Number | Description | |||
| 2.1 | — | Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. and New Source Energy Corporation (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on April 4, 2013). | ||
| 2.2 | — | Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. and Scintilla, LLC (Incorporated by reference to Exhibit 2.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on April 4, 2013). | ||
| 2.3 | — | Contribution Agreement, dated as of March 29, 2013, by and between New Source Energy Partners L.P. and W.K. Chernicky, LLC (Incorporated by reference to Exhibit 2.3 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on April 4, 2013). | ||
| 2.4 | — | Contribution Agreement, dated as of October 4, 2013, by and between New Source Energy Partners L.P. and Scintilla, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on October 10, 2013). | ||
| 2.5 | — | Contribution 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, Signature Investments, LLC and MCE, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 18, 2013). | ||
| 2.6 | — | Contribution Agreement dated as of January 31, 2014, by and between New Source Energy Partners L.P. and CEU Paradigm, LLC (Incorporated by reference to Exhibit 2.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 5, 2014). | ||
| 3.1 | — | Certificate of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.1 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013). | ||
| 3.2 | — | Agreement of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.2 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013). | ||
| 3.3 | — | First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P. (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 3.4 | — | First Amendment to the First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P., dated as of November 12, 2013 (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 18, 2013). | ||
| 3.5 | — | Certificate of Formation of New Source Energy GP, LLC (Incorporated by reference to Exhibit 3.4 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013). | ||
| 3.6 | — | Limited Liability Company Agreement of New Source Energy GP, LLC (Incorporated by reference to Exhibit 3.5 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 11, 2013). | ||
| 3.7 | — | Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC (Incorporated by reference to Exhibit 3.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 3.8 | — | Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC (Incorporated by reference to Exhibit 3.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on March 20, 2013). | ||
| 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 (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 18, 2013). | ||
| 4.2 | — | Registration Rights Agreement, dated as of December 20, 2013, by and between New Source Energy Partners L.P. and Goldman Sachs MLP Income Opportunities Fund (Incorporated by reference to Exhibit 4.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on December 23, 2013). | ||
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| Exhibit Number | Description | |||
| 10.1 | — | Contribution, Conveyance and Assumption Agreement, dated as of February 13, 2013, by and among New Source Energy Corporation, New Source Energy GP, LLC and New Source Energy Partners L.P. (Incorporated by reference to Exhibit 10.7 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 10.2 | — | Development Agreement, dated as of February 13, 2013, by and among New Source Energy Partners L.P., New Source Energy GP, LLC, New Source Energy Corporation and New Dominion, LLC (Incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 10.3† | — | New Source Energy Partners L.P. Long-Term Incentive Plan, dated January 30, 2013 (Incorporated by reference to Exhibit 4.3 of the Partnership’s Registration Statement on Form S-8 (File No. 333-186673) filed on February 13, 2013). | ||
| 10.4† | — | Form of Restricted Unit Agreement (Subordinated Period Vesting) (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 12, 2013). | ||
| 10.5† | — | Form of Restricted Unit Agreement (Time-based Vesting) (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 12, 2013). | ||
| 10.6 | — | Omnibus Agreement, dated February 13, 2013, by and among New Source Energy Corporation, New Source Energy GP, LLC and New Source Energy Partners L.P. (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 10.7 | — | Golden Lane Participation Agreement, dated as of January 10, 2007, among New Dominion, LLC, as operator, Scintilla, LLC and certain other working interest holders in the Golden Lane field party thereto (Incorporated by reference to Exhibit 10.6 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 25, 2013). | ||
| 10.8 | — | First Amendment to Golden Lane Participation Agreement, dated as of October 20, 2007, among New Dominion, as operator, and certain other working interest holders in the Golden Lane field party thereto (Incorporated by reference to Exhibit 10.7 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 25, 2013). | ||
| 10.9 | — | Assignment and Assumption Agreement, dated as of August 12, 2011, between New Source Energy Corporation, as assignee, and Scintilla, LLC, as assignor (Incorporated by reference to Exhibit 10.8 of the Partnership’s Registration Statement on Form S-1 (File No. 333-185754) filed on January 25, 2013). | ||
| 10.10 | — | Assignment and Assumption Agreement, dated as of February 13, 2013, between New Source Energy Partners L.P., as assignee, and New Source Energy Corporation, as assignor (Incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 10.11 | — | Form of Director Indemnification Agreement (Incorporated by reference to Exhibit 10.5 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 10.12 | — | Subordinated Promissory Note, dated February 13, 2013, by and among New Source Energy Partners L.P., as borrower and New Source Energy Corporation, as lender (Incorporated by reference to Exhibit 10.6 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 10.13 | — | Credit Agreement, dated as of February 13, 2013, among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent for the lenders party thereto, and the other lender parties thereto (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on February 15, 2013). | ||
| 10.14 | — | First Amendment to Credit Agreement, dated as of February 28, 2013, by and among the Partnership, as borrower, Bank of Montreal, as administrative agent, Associated Bank, N.A., as syndication agent, and the other lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on March 6, 2013). | ||
| 10.15 | — | 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 (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on June 28, 2013). | ||
| 10.16 | — | Third Amendment to Credit Agreement, dated as of October 29, 2013, by and among the Partnership, as borrower, Bank of Montreal, as administrative agent, Associated Bank, N.A., as syndication agent, and the other lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 4, 2013). | ||
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| Exhibit Number | Description | |||
| 10.17 | — | 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 (Incorporated by reference to Exhibit 10.4 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 18, 2013). | ||
| 10.18 | — | Purchase and Sale Agreement between New Source Energy Partners L.P. and Scintilla, LLC dated July 23, 2013 (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on July 29, 2013). | ||
| 10.19 | — | 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 (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 18, 2013). | ||
| 10.20 | — | Amended and Restated Agreement of Limited Partnership of MCE, LP, dated as of November 12, 2013 (Incorporated by reference to Exhibit 10.2 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 18, 2013). | ||
| 10.21 | — | 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 (Incorporated by reference to Exhibit 10.3 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on November 18, 2013). | ||
| 10.22 | — | Common Unit Purchase Agreement, dated as of December 17, 2013, by and among New Source Energy Partners L.P. and Goldman Sachs MLP Income Opportunities Fund (Incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K (File No. 001-35809) filed on December 23, 2013). | ||
| 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. | ||
| 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 * | — | XBRL Instance Document. | ||
| 101 SCH * | — | XBRL Schema Document. | ||
| 101 CAL * | — | XBRL Calculation Linkbase Document. | ||
| 101 DEF * | — | XBRL Definition Linkbase Document. | ||
| 101 LAB * | — | XBRL Labels Linkbase Document. | ||
| 101 PRE * | — | XBRL Presentation Linkbase Document. | ||
* Filed herewith.
** Furnished herewith.
† Management contract or compensatory plan or arrangement
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on April 4, 2014.
| New Source Energy Partners L.P. | |||
| By: | New Source Energy GP, LLC, its general partner | ||
| /s/ Kristian B. Kos | |||
| By: | Kristian B. Kos | ||
| Title: | Chief Executive Officer | ||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated.
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| Signature | Title | Date | |||
| /s/ David J. Chernicky | Chairman of the Board | April 4, 2014 | |||
| David J. Chernicky | and Senior Geologist | ||||
| /s/ Kristian B. Kos | Director, President | April 4, 2014 | |||
| Kristian B. Kos | and Chief Executive Officer | ||||
| (Principal Executive Officer) | |||||
| /s/ Richard D. Finley | Chief Financial Officer and Treasurer | April 4, 2014 | |||
| Richard D. Finley | (Principal Financial Officer and | ||||
| Principal Accounting Officer) | |||||
| /s/ Terry L. Toole | Director | April 4, 2014 | |||
| Terry L. Toole | |||||
| /s/ V. Bruce Thompson | Director | April 4, 2014 | |||
| V. Bruce Thompson | |||||
| /s/ Phil Albert | Director | April 4, 2014 | |||
| Phil Albert | |||||
| /s/ John A. Raber | Director | April 4, 2014 | |||
| John A. Raber | |||||
| /s/ Charles Lee Reynolds III | Director | April 4, 2014 | |||
| Charles Lee Reynolds III | |||||
| /s/ Dikran Tourian | Director | April 4, 2014 | |||
| Dikran Tourian | |||||
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