CIVITAS RESOURCES, INC. - Annual Report: 2013 (Form 10-K)

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UNITED STATES
SECURITIES AND COMMISSION
Washington, D.C. 20549

Form 10-K

Commission file number: 001-35371

Bonanza Creek Energy, Inc.
(Exact name of registrant as specified in its charter)

(720) 440-6100
(Registrant's telephone number, including area code)

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

         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 ý    No o

         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 ý

         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 ý    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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    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 Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

         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.

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

         The aggregate market value of the registrant's voting and non-voting common equity held by non-affiliates on June 28, 2013, based upon the closing price of $35.46 of the registrant's common stock as reported on the New York Stock Exchange, was approximately $847,821,792. Excludes approximately 16,377,774 shares of the registrant's common stock held by executive officers, directors and stockholders that the registrant has concluded, solely for the purpose of the foregoing calculation, were affiliates of the registrant.

         Number of shares of registrant's common stock outstanding as of February 24, 2014: 40,267,540

Documents Incorporated By Reference:

         Portions of the registrant's definitive proxy statement for its 2014 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2013, are incorporated by reference into Part III of this report for the year ended December 31, 2013.

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BONANZA CREEK ENERGY, INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2013

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Information Regarding Forward-Looking Statements

        This Annual Report on Form 10-K contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historic fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities and Exchange Act of 1934, as amended. When used in this Annual Report on Form 10-K, the words "could," "believe," "anticipate," "intend," "estimate," "expect," "may," "continue," "predict," "potential," "project," "plan" "will," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

        Forward-looking statements include statements related to, among other things:

•

reserves estimates;



•

estimated production for 2014;



•

amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;



•

ability to modify future capital expenditures;



•

the Wattenberg Field being the most prospective area of the Niobrara formation and the Dorcheat Macedonia Field being a primary focus in the Mid-Continent region;



•

compliance with debt covenants;



•

ability to satisfy obligations related to ongoing operations;



•

compliance with government regulations;



•

adequacy of gathering systems and impact from the lack of available gathering systems and processing facilities in certain areas;



•

natural gas, oil and NGL prices and factors affecting the volatility of such prices;



•

impact of lower commodity prices;



•

the ability to use derivative instruments to manage commodity price risk;



•

plans to drill or participate in wells including the intent to focus in specific areas or formations;



•

loss of any purchaser of our products;



•

our estimated revenues and losses;



•

the timing and success of specific projects;



•

intentions with respect to acquisitions and divestitures;



•

intentions with respect to working interest percentages;



•

management and technical team;



•

outcomes and effects of litigation, claims and disputes;



•

our business strategy;



•

our ability to replace oil and natural gas reserves;



•

impact of recently issued accounting pronouncements;



•

our financial position;

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•

our cash flow and liquidity; and



•

other statements concerning our operations, economic performance and financial condition.

        We have based these forward-looking statements on certain assumptions and analyses we have made in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control, and may not be realized or, even if substantially realized, may not have the expected consequences. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to, the following:

•

the risk factors discussed in Part I, Item 1A of this Annual Report on Form 10-K;



•

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



•

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



•

the continuing global economic slowdown that has and may continue to adversely affect consumption of oil and natural gas by businesses and consumers;



•

ability of our customers to meet their obligations to us;



•

our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fully develop our undeveloped acreage positions;



•

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 gas reserves and, in particular, probable and possible resources;



•

the possibility that the industry may be subject to future local, state, and federal regulatory or legislative actions (including additional taxes and changes in environmental regulation);



•

environmental risks;



•

seasonal weather conditions and lease stipulations;



•

drilling and operating risks, including the risks associated with the employment of horizontal drilling techniques;



•

ability to acquire adequate supplies of water for drilling and completion operations;



•

availability of oilfield equipment, services and personnel;



•

exploration and development risks;



•

competition in the oil and natural gas industry;



•

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



•

risks related to our derivative instruments;



•

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



•

ability to maintain effective internal controls;

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•

access to adequate gathering systems and pipeline take-away capacity to provide adequate infrastructure for the products of our drilling program;



•

our ability to secure firm transportation for oil and natural gas we produce and to sell the oil and natural gas at market prices;



•

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



•

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.

        All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. We disclaim any obligation to update or revise these statements unless required by law, and you should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under Item 1A. Risk Factors and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and elsewhere in this Annual Report on Form 10-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

GLOSSARY OF OIL AND NATURAL GAS TERMS

        We have included below the definitions for certain terms used in this Annual Report on Form 10-K:

        "3-D seismic data" Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic data typically provide a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic data.

        "Analogous reservoir" Analogous reservoirs, as used in resources 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, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);



(ii)

Same environment of deposition;



(iii)

Similar geological structure; and



(iv)

Same drive mechanism.

        "Bbl" One barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

        "Bcf" One billion cubic feet of natural gas.

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

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        "British thermal unit" or "BTU" The heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

        "Basin" A large natural depression on the earth's surface in which sediments generally brought by water accumulate.

        "Completion" The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

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

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

        "Development costs" Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves; (ii) drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly; (iii) acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (iv) provide improved recovery systems.

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

        "Dry hole" Exploratory or development well that does not produce oil or gas in commercial quantities.

        "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 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.

        "ERISA" Employee Retirement Income Security Act of 1974.

        "Estimated ultimate recovery (EUR)" Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

        "Exploratory well" A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.

        "Field" An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent

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fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

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

        "GAAP" Generally accepted accounting principles in the United States.

        "HH" Henry Hub index.

        "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.

        ""Hydraulic fracturing" The process of injecting water, proppant and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production.

        "LIBOR" London international offered rate.

        "MBbl" One thousand barrels of oil or other liquid hydrocarbons.

        "MBoe" One thousand Boe.

        "Mcf" One thousand cubic feet.

        "MMBoe" One million Boe.

        "MMBtu" One million British Thermal Units.

        "MMcf" One million cubic feet.

        "NYMEX" The New York Mercantile Exchange.

        "Net acres" The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

        "Net revenue interest" Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from the working interest ownership.

        "Net well" Deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interest owned in gross wells expressed as whole numbers and fractions of whole numbers.

        "Oil and gas producing activities" defined as (i) the search for crude oil, including condensate and natural gas liquids, or natural gas in their natural states and original locations; (ii) the acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties; (iii) the construction, drilling and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as lifting the oil and gas to the surface' and gathering, treating and field processing (as in the case of processing gas to extract liquid hydrocarbons); and (iv) extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coal beds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

        "Play" A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and gas reserves.

        "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 many states require plugging of abandoned wells.

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        "Pooling" Pooling is a provision in an oil and gas lease that allows the operator to combine the leased property with properties owned by others. (Pooling is also known as unitization.) The separate tracts are joined to form a drilling unit. Ownership shares are issued according to the acreage contributed or by the production capabilities of each producing well for Fields in later stages of development.

        "Possible reserves" Those additional reserves that are less certain to be recovered than probable reserves (i) when deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates; (ii) possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project; (iii) possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves; (iv) the proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects; (v) possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower that the proved area if these areas are in communication with the proved reservoir; (vi) where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

        "Probable reserves" Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates; (ii) probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved if these areas are in communication with the proved reservoir; (iii) probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

        "Production costs" Costs incurred to operated and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are (a) costs of labor to operate the wells and related equipment and facilities; (b) repairs and maintenance; (c) materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities; (d) property taxes and insurance applicable to proved properties and

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

        "Productive well" A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

        "Proppant" Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment. In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used. Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

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

        "Proved reserves" Those quantities of oil and 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.

(i)

The area of the reservoir considered as proved includes:



(a)

The area identified by drilling and limited by fluid contacts, if any, and



(b)

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 gas on the basis of available geoscience and engineering data.



(ii)

In the absence of data on fluid contracts, 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.



(iii)

Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher potions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.



(iv)

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:



(a)

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

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establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

(b)

The project has been approved for development by all necessary parties and entities, including governmental entities.



(v)

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-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" or "PUD" Proved 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 directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedule to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall 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 projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

        "PV-10" A non-GAAP financial measure that represents inflows from proved crude oil and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash inflows and using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices (after adjustment for differentials in location and quality) for each of the preceding twelve months. See footnote (2) to the Proved Reserves table in Item 1. "Business" of this Annual Report on Form 10-K for more information.

        "Reasonable certainty" If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical and geochemical) engineering, and economic data are made to estimated ultimate EUR recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

        "Recompletion" The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

        "Reserves" Estimated remaining quantities of oil and 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 gas or related substances to market, and all permits and financing required to implement the project.

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

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        "Resource play" Refers to drilling programs targeted at regionally distributed oil or natural gas accumulations. Successful exploitation of these reservoirs is dependent upon new technologies such as horizontal drilling and multi-stage fracture stimulation to access large rock volumes in order to produce economic quantities of oil or natural gas.

        "Royalty interest" An interest in an oil and natural gas property entitling the owner to a share of oil or gas production free of production costs, but subject to severance taxes (unless the owner is agreement agency).

        "Spacing" Regulation concerning the number of wells which can be drilled on a given area of land. Depending on the depth of the reservoir, one well may be allowed on a small area of five acres or on an area up to 640 acres. Typical spacing is 40 acres for oil wells and 640 acres for gas wells. Also referred to as "well spacing."

        "Undeveloped acreage" Those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

        "Undeveloped reserves" Undeveloped oil and gas reserves are reserves of any category 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. Also referred to as "undeveloped oil and gas reserves."

        "Working interest" The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

        "WTI" West Texas Intermediate index.

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PART I

Item 1.    Business.

        When we use the terms "Bonanza Creek," the "Company," "we," "us," or "our" we are referring to Bonanza Creek Energy, Inc. and its subsidiaries unless the context otherwise requires. We have included certain technical terms important to an understanding of our business under Glossary of Oil and Gas Terms above. Throughout this document we make statements that may be classified as "forward-looking." Please refer to the Information Regarding Forward-Looking Statements section above for an explanation of these types of statements.

Overview

        Bonanza Creek is an independent energy company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado, which we have designated the Rocky Mountain region, and the Dorcheat Macedonia Field in Southern Arkansas, which we have designated the Mid-Continent region. In addition, we own and operate oil-producing assets in the North Park Basin in Colorado and the McKamie Patton Field in Southern Arkansas. Our management team has extensive experience acquiring and operating oil and gas properties and significant expertise in horizontal drilling and fracture stimulation, which we believe will contribute to the development of our sizable inventory of projects. We operate approximately 99% of our proved reserves with an average working interest of approximately 89% providing us with significant control over the rate of development of our asset base.

        We are currently focused on the horizontal development of significant resource potential from the Niobrara and Codell formations in the Wattenberg Field, expecting to invest approximately 85% of our 2014 capital budget in this project. The remaining 15% of our 2014 budget is allocated primarily to the vertical development of the Dorcheat Macedonia and McKamie Patton Fields in southern Arkansas, targeting oil-rich Cotton Valley sands. We believe the location, size and concentration of our acreage in our core project areas provide an opportunity to significantly increase production, lower costs and further delineate the Company's resource potential. In 2013, we successfully drilled 134 and completed 121 productive operated wells and participated in drilling 12 and completing 4 productive non-operated wells. We had 17 operated wells in progress as of December 31, 2013. The resulting production rates achieved by this program increased sales volumes by 72% over the previous year to 16,219 Boe/d of which 72% was crude oil and natural gas liquids ("NGL"). The Rocky Mountain region contributed 66% and the Mid-Continent region contributed 34% to total production. Our average net daily production rate during December 2013 was 19,649 Boe/d, a 58% increase over December 2012.

        In the second quarter 2012, we began the divestiture process of our non-core properties in California. The California properties were treated as assets held for sale, and production, revenue and expenses associated with these properties were removed from continuing operations and reported as discontinued operations. Those results are included in the following discussions unless otherwise noted. During 2012, we sold the majority of these properties for approximately $9.3 million in aggregate, with one property remaining to be sold as of December 31, 2013.

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        Netherland, Sewell & Associates, Inc., our independent reserve engineers, estimated our net proved reserves as of December 31, 2013, to be as follows:

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Our History

        Bonanza Creek Energy, Inc. was incorporated on December 2, 2010 pursuant to the laws of the State of Delaware. On December 23, 2010, in connection with an investment from Project Black Bear LP, an entity advised by West Face Capital Inc. ("West Face Capital") and certain clients of Alberta Investment Management Corporation ("AIMCo"), we acquired Bonanza Creek Energy Company, LLC ("BCEC") and Holmes Eastern Company, LLC ("HEC"), which transactions we refer to as our "Corporate Restructuring." We completed the initial public offering of our common stock in December 2011 (our "IPO") pursuant to which 10,000,000 shares of our common stock were sold.

Our Business Strategies

        Our primary goal is to increase stockholder value by investing capital in projects that provide attractive rates of return relative to our cost of capital, and increase our production, proved reserves and cash flow. We intend to accomplish this by focusing on the following key strategies:

•

Increase Production from Wattenberg Horizontal Opportunities and Develop Additional Resource Potential in Both of our Core Areas.  We intend to continue to develop the Niobrara and Codell formations utilizing horizontal drilling. While we are focused on the Niobrara B bench, primarily using 4,000 foot laterals, we have begun, and plan to continue, to develop the Niobrara C bench and Codell formation as well as to test extended reach lateral drilling in the Wattenberg Field and down-spacing concepts in both of our core areas. We expect to continue to generate profitable, long-term reserve and production growth predominantly through repeatable, lower-risk development drilling on our assets, which have multiple resource horizons.



•

Pursue Ongoing Corporate Growth.  We intend to pursue bolt-on acquisitions in the Wattenberg Field and in southern Arkansas where we can take advantage of our core operational and engineering competencies. In addition, we will evaluate acquisitions of other opportunities where we believe the application of our core competencies will enhance shareholder value.



•

Maintain High Degree of Operatorship.  We currently have and intend to maintain a high working interest in our assets, thereby allowing us to leverage our technical, operating, and management skills and control the timing of our capital expenditures.



•

Manage Risk Exposure.  In order to achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in oil prices, we have entered into and intend in the future to enter into derivative contracts for a significant portion of our expected oil production.

Our Competitive Strengths

We believe the following combination of strengths will enable us to implement our strategies:

•

High Quality Asset Base with Oil and Liquids-Weighted Growth.  As of December 31, 2013, we have accumulated approximately 35,500 net acres in the Wattenberg Field prospective for the Niobrara formation, of which, approximately 18,000 net acres have been successfully tested to have prospective for the Codell formation. We will continue to test our remaining Wattenberg Field acreage to prove out the Codell formation. Our acreage is in an area noted for its high net oil and liquids content, with oil and NGLs comprising approximately 65% of proved reserves and approximately 73% of current production, yielding strong economic returns at current commodity prices. We believe our acreage position represents a large inventory of high value, ready-to-drill potential locations with significant upside potential and that the consistently

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positive results in this play by us and other operators validate our investment and the continued development of the area. We believe adequate gathering systems and takeaway capacity are in place in this area, enabling a short time period from well completion to first product sales.

•

Contiguous Nature of Our Leasehold.  Our acreage positions in the Wattenberg Field and in the Mid-Continent region are highly contiguous which allows for more efficient field operations. In the Wattenberg Field, we believe our leasehold is particularly advantaged for development with horizontal wells and extended reach laterals.



•

High Degree of Operational Control.  We operate approximately 99% of our proved reserves with an average working interest of approximately 89% providing us with significant control over the rate of development of our asset base. This allows us to employ the drilling and completion techniques we believe to be most effective, manage costs and control the timing and allocation of our capital expenditures.



•

Gas Processing Capability in Southern Arkansas.  We own three gas processing facilities and 150 miles of gathering pipeline that principally serve our production from the Dorcheat Macedonia Field and our McKamie Patton Field properties. We believe the ownership of this gathering and processing infrastructure allows us to better control the timing of the development of our reserves and improves our economics in southern Arkansas.



•

Experienced Management Team with Proven Track Record.  Our senior management team has extensive experience in the oil and gas industry. Our senior technical team averages more than 30 years of industry experience, including experience in multiple North American resource plays and basins. We believe our management and technical team is one of our principal competitive strengths due to its proven track record in identification, acquisition and execution of resource conversion opportunities. In addition, this team possesses substantial expertise in horizontal drilling techniques and fracture stimulation.



•

Financial Flexibility.  Our capital structure is intended to provide a high degree of financial flexibility to grow our asset base, both through organic projects and opportunistic acquisitions. Our liquidity as of December 31, 2013 was approximately $595 million, which was comprised of $414 million of availability under our credit facility, if we elect to take advantage of our entire borrowing base, and approximately $181 million of cash on hand. We also employ a disciplined approach to management of leverage and govern our organic capital spending programs.

Our Operations

        Our operations are mainly focused in the Wattenberg Field in the Rocky Mountain region and in the Dorcheat Macedonia Field in the Mid-Continent region.

Rocky Mountain Region

        The two main areas in which we operate in the Rocky Mountain region are the Wattenberg Field in Weld County, Colorado and the North Park Basin in Jackson County, Colorado.

        Wattenberg Field—Weld County, Colorado.    Our operations are in the oil and liquids-weighted extension area of the Wattenberg Field targeting the Niobrara and Codell formations. As of December 31, 2013, our Wattenberg position consisted of approximately 40,000 gross (35,500 net) acres. During 2013, we had a net increase of approximately 4,500 net acres in the Wattenberg Field, which includes an increase in net acreage of approximately 5,250 acres through acquisitions and leasing in our core area and a reduction of approximately 750 net acres due to expiration of non-core lands, adjustments in ownership due to further title information and other adjustments including strategic partnerships and pooling arrangements. We own 3-D seismic surveys covering substantially all of our

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acreage in the Wattenberg Field, which helps provide efficient and targeted horizontal drilling operations.

        The Wattenberg Field is now primarily developed for the Niobrara and Codell formations using horizontal drilling and multi-stage fracture stimulation techniques. We believe our acreage position has been fully delineated for the Niobrara B bench and expect this horizon to be a primary source of future production growth. In addition, our testing in the Niobrara C bench and Codell formation has been successful to date and supports future delineation and development drilling.

        Our estimated proved reserves at December 31, 2013 in the Wattenberg Field were 48,725 MBoe. As of December 31, 2013, we had a total of 313 gross producing wells, of which 124 gross were horizontal wells, and our average daily production during 2013 was approximately 10,495 Boe/d, of which 91% came from horizontal wells. Our average daily production for the month of December 2013 was 13,619 Boe/d. Our working interest for all producing wells averages approximately 91% and our net revenue interest is approximately 82%

        We continue to expand our proved reserves in this area by drilling non-proved horizontal locations. During 2013, we drilled 87 horizontal wells and successfully completed 73. In the Niobrara B bench, we drilled 69 and successfully completed 62 standard length (4,000 foot lateral) horizontal wells and two extended reach horizontal wells with average lateral length of 9,240 feet during 2013. Since we began our horizontal Niobrara B bench drilling program in 2011, through December 31, 2013, we have drilled and successfully completed 98 wells of which 92 are on 80-acre spacing and 6 are on 40-acre spacing. We believe the results demonstrated by our wells spaced at 40 acres warrant continued development of the Niobrara B bench at that spacing density. In addition, we believe the results demonstrated by our extended reach laterals warrant continued testing of lateral lengths of greater than 4,000 feet. In the Niobrara C bench and Codell formation, we drilled 10 and 6 standard length (4,000 foot lateral) horizontal wells, respectively, and successfully completed 5 and 4 standard length (4,000 foot lateral) horizontal wells during 2013. The drilling results demonstrated in the Niobrara C bench and Codell formation were in-line with expectations and provide the basis for our accelerated development plan during 2014.

        We estimate our capital expenditures in the Wattenberg Field for 2014 will be $493 million to $533 million, which includes drilling a projected 87 horizontal wells in the Niobrara B bench, 16 horizontal wells in the Niobrara C bench, one horizontal well in the Niobrara A bench and 17 horizontal wells in the Codell sandstone. This drilling program includes approximately 23 proved locations and 98 non-proved locations and approximately $28 million for non-operated horizontal drilling.

        North Park Basin—Jackson County, Colorado.    We control approximately 22,000 gross (17,000 net) acres in the North Park Basin in Jackson County, Colorado, all prospective for the Niobrara oil shale. We operate the North and South McCallum Fields, which currently produce light oil and CO₂ from the Dakota/Lakota Group sandstones and oil from a shallow waterflood in the Pierre B sandstone. Oil production is trucked to market, while CO₂ production is gathered to a nearby plant for processing.

        In the North Park Basin, our estimated proved reserves as of December 31, 2013 were approximately 270 MBoe, 100% of which were crude oil. Our average net production during 2013 was approximately 123 Boe/d. None of our CO₂ production is currently reflected in our reserve reports.

        Currently, there is no takeaway capacity for natural gas from the North Park Basin. Any future commercial development of the Niobrara shale in this area will require significant investment to construct the infrastructure necessary to gather and transport the produced associated natural gas. We have budgeted approximately $7 million during 2014 to drill two exploration wells in the North Park Basin.

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Mid-Continent Region

        In southern Arkansas, we target the oil-rich Cotton Valley sands in the Dorcheat Macedonia and McKamie Patton Fields. As of December 31, 2013, our estimated proved reserves in this region were 20,744 MBoe, 69% of which were oil and natural gas liquids and 59% of which were proved developed. We currently operate 237 producing vertical wells and, as of December 31, 2013, have an identified drilling inventory of approximately 112 gross (93 net) PUD drilling locations on our acreage. During 2013, we drilled 47 wells and successfully completed 48 wells in the Dorcheat Macedonia and McKamie Patton Fields. We achieved an average production rate for 2013 of 5,554 Boe/d, of which 70% was from crude oil and liquids, and an average production rate for December 2013 of 5,889 Boe/d. Productive reservoirs range in depth from 4,500 to 9,000 feet in depth. Those reservoirs include the Smackover and the Pettet, but our primary development target is the Cotton Valley.

        Dorcheat Macedonia.    In the Dorcheat Macedonia Field, we average an approximate 84% working interest and an approximate 70% net revenue interest on all producing wells, and the majority of our acreage is held by unitization, production, or drilling operations. We have approximately 190 gross producing wells and our average net daily production during 2013 was approximately 5,116 Boe/d. During the month of December 2013, it was approximately 5,541 Boe/d. Our proved reserves in this field are approximately 19,377 MBoe. Prior to 2013, the development plan for the Dorcheat Macedonia Field was based on a maximum well density equal to 10-acre spacing. Late in 2012, we initiated the first of three pilot tests which increased well density to 5-acre spacing. Results from these pilots are encouraging and we plan to allocate 19% of our 2014 capital budget in the Mid-Continent region to this down-spacing project.

        As of December 31, 2013, we have identified approximately 110 gross (91 net) PUD drilling locations on our acreage in this area. During 2013, we drilled 44 and successfully completed 45 vertical Cotton Valley wells in Dorcheat Macedonia. We have budgeted capital expenditures for 2014 of approximately $75 million to $85 million for the development of this field. In 2014, we expect to drill 34 PUD locations on 10-acre spacing with a complete cost per well of approximately $1.8 million, approximately $1.7 million of which will be for initial drilling and completion with the remaining $100,000 attributed to the first recompletion generally executed within six months of first production. In addition, we expect to drill 10 wells on 5-acre spacing and perform 112 recompletions on existing wells.

        Other Mid-Continent.    We own additional interests in our Mid-Continent region near the Dorcheat Macedonia Field. These include interests in the McKamie Patton, Atlanta and Beech Creek Fields. As of December 31, 2013, our estimated aggregate proved reserves in these fields were approximately 1,367 MBoe, and average net daily production during 2013 was approximately 438 Boe/d. During 2013, we drilled 3 vertical Cotton Valley wells in the McKamie-Patton Field. In 2014, we expect to continue development at McKamie-Patton with 4 vertical Cotton Valley wells.

        Gas Processing Facilities.    Our Mid-Continent gas processing facilities are located in Lafayette and Columbia counties in Arkansas and are strategically located to serve our production in the region. In the aggregate, our Arkansas gas processing facilities have approximately 40 MMcf/d of capacity with 86,000 gallons per day of associated natural gas liquids capacity. Our ownership of these facilities and related gathering pipeline provides us with the benefit of controlling processing and compression of our natural gas production and timing of connection to our newly completed wells.

Reserves

Estimated Proved Reserves

        Unless otherwise specifically identified, the summary data with respect to our estimated proved reserves presented below has been prepared by our independent reserve engineering firm in accordance with rules and regulations of the Securities and Exchange Commission (the "SEC") applicable to

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companies involved in oil and natural gas producing activities. Our proved reserve estimates do not include probable or possible reserves which may exist, categories which the new SEC rules now permit us to disclose in public reports. Our estimated proved reserves for the years ended December 31, 2013, 2012, and 2011 and for future periods are determined using the preceding twelve-months' unweighted arithmetic average of the first-day-of-the-month prices. For a definition of proved reserves under the SEC rules, please see the Glossary of Oil and Natural Gas Terms included in the beginning of this report.

        Reserve estimates are inherently imprecise and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The PV-10 values shown in the following table are not intended to represent the current market value of our estimated proved reserves. Neither prices nor costs have been escalated. The actual quantities and present values of our estimated proved reserves may be less than we have estimated. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the SEC, since the beginning of the last fiscal year.

        The table below summarizes our estimated proved reserves at December 31, 2013, 2012, and 2011 for each of the areas in which we operate. The proved reserve estimates at December 31, 2013 presented in the table below are based on reports prepared by Netherland, Sewell & Associates, Inc., our independent reserve engineers, whereas the December 31, 2012 and 2011 estimated proved reserved were prepared by Cawley, Gillespie & Associates, Inc. In preparing these reports, Netherland, Sewell & Associates, Inc. and Cawley, Gillespie & Associates, Inc. evaluated 100% of our properties at December 31, 2013, 2012, and 2011. For more information regarding our independent reserve engineers, please see Independent Reserve Engineers below. The information in the following table does not give any effect to or reflect our commodity derivatives.

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        The following table sets forth more information regarding our estimated proved reserves at December 31, 2013, 2012, and 2011:

        Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are 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 completion. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled. All proved undeveloped locations in our December 31, 2013 reserves report are scheduled to be drilled within five years from their initial proved booking date. The technologies used to establish our proved reserves are a combination of geologic mapping, electric logs, seismic data and production data.

        Estimated proved reserves at December 31, 2013 were 69.8 MMBoe, a 32% increase from estimated proved reserves of 53.0 MMBoe at December 31, 2012. The net increase in reserves of 16.8 MMBoe resulting from development in the Wattenberg Field is comprised of 28.9 MMBoe of additions in extensions and discoveries offset by 3.8 MMBoe in production and negative revisions of 8.3 MMBoe. The negative revision results primarily from a combination of eliminating 45 net vertical locations from proved undeveloped due to the change in focus from vertical to horizontal development, the elimination of all proved non-producing reserves associated with vertical well refracs, recompletions, and lower performance from our vertical producers due to increased line pressure. The addition in extension and discoveries is the result of drilling and completing 68 unproved horizontal locations

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(including 4 non-operated) in the Wattenberg Field during 2013 and the addition of 89 new horizontal proved undeveloped locations. A net increase in reserves of 0.1 MMBoe in the Mid-Continent region resulted from the drilling and completion of our 5-acre increased density pilots in the Cotton Valley formation offset by a negative revision resulting from lower than expected proved developed performance. A small positive pricing revision of 0.51 MMBoe resulted from an increase in average commodity price from $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012 to $96.91 per Bbl WTI and $3.67 per MMBtu HH for the year ended December 31, 2013.

        Estimated proved reserves at December 31, 2012 were 53.0 MMBoe, a 21% increase from estimated proved reserves of 43.7 MMBoe at December 31, 2011. The net increase in reserves of 9.3 MMBoe resulted from development in the Wattenberg Field was comprised of 18.9 MMBoe of additions in extensions and discoveries offset by 3.5 MMBoe in production and negative revisions of 6.1 MMBoe. The negative revision results from a combination of eliminating 50 locations from proved undeveloped due to the change in focus from vertical to horizontal development and lower performance from our vertical producers. The addition in extension and discoveries is the result of drilling and completing 65 unproved locations in the Wattenberg Field during 2012 (approximately 50% horizontal Niobrara B bench locations, 50% vertical development) and the addition of 63 new proved undeveloped locations (100% horizontal Niobrara B bench locations). A net increase in reserves of 0.68 MMBoe in the Mid-Continent region resulted from continued development of the Cotton Valley formation. Proved reserves decreased by 0.67 MMBoe with the divestiture of the majority of our California properties. A small negative pricing revision of 0.1 MMBoe resulted from a decrease in commodity price from $96.19 per Bbl WTI and an average price of $4.12 per MMBtu HH for the year ended December 31, 2011 to $94.71 per Bbl WTI and $2.76 per MMBtu HH for the year ended December 31, 2012.

        Estimated proved reserves at December 31, 2011 were 43.7 MMBoe, a 33% increase from estimated proved reserves of 32.9 MMBoe at December 31, 2010. All proved undeveloped locations included in our December 31, 2011 reserves report are scheduled to be drilled within five years from their initial proved booking date. The increase was primarily due to extensions and discoveries associated with the Rocky Mountain region and was comprised of 168 new proved undeveloped locations and 54 unproved locations that were drilled during 2011 and moved directly to proved reserves. Another component of the increase was our commodity price assumption for oil which increased $16.76 per Bbl WTI to $96.19 per Bbl WTI for the year ended December 31, 2011 from $79.43 per Bbl WTI for the year ended December 31, 2010.

Reconciliation of PV-10 to Standardized Measure

        PV-10 is derived from the Standardized Measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the Standardized Measure on a pre-tax basis. PV-10 is equal to the Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the Standardized Measure. Our PV-10 measure and the Standardized Measure do not purport to present the fair value of our oil and natural gas reserves.

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        The following table provides a reconciliation of PV-10 to the Standardized Measure at December 31, 2013, 2012 and 2011:

Proved Undeveloped Reserves

        At December 31, 2013, our proved undeveloped reserves were 37,603 MBoe, all of which are scheduled to be drilled within five years of their initial disclosure. At December 31, 2012, our proved undeveloped reserves were 29,192 MBoe. During 2013, 3,047 MBoe or 10% of our proved undeveloped reserves (40 wells) were converted into proved developed reserves requiring $62.8 million of drilling and completion capital. Continued delineation and testing in our Wattenberg Field in 2013 resulted in a conversion rate less than 20% for the year. In 2014, our drilling plans include proved undeveloped drilling estimated to convert over 20% of our proved undeveloped reserves into proved developed reserves. Executing our 2013 capital program resulted in the addition of 16,535 MBoe in proved undeveloped reserves (92 wells). The negative revision of 6,856 MBoe results from a combination of eliminating vertical proved undeveloped locations in the Wattenberg Field continuing the transition to horizontal development and a reduction in proved undeveloped reserves in the Dorcheat Macedonia Field based on proved developed performance.

        At December 31, 2012, our proved undeveloped reserves were 29,192 MBoe, all of which were scheduled to be drilled within five years of their initial disclosure. At December 31, 2011, our proved undeveloped reserves were 26,652 MBoe. During 2012, 5,166 MBoe or 19.4% of our proved undeveloped reserves (89 wells) were converted into proved developed reserves requiring $128.9 million of drilling and completion capital and $16.2 million of capital primarily used to expand our Dorcheat Macedonia gas plant. Executing our 2012 capital program resulted in the addition of 13,913 MBoe in proved undeveloped reserves (83 wells). Sales of the majority of our California properties during 2012 reduced our proved undeveloped reserves by 430 MBoe. The negative revision of 5,777 MBoe results from a combination of eliminating 50 locations in the Wattenberg Field from proved undeveloped due to the change in focus from vertical to horizontal development and the reduction in remaining vertical proved undeveloped reserves as a result of lower performance from our vertical producers.

        At December 31, 2011, our proved undeveloped reserves were 26,652 MBoe, all of which were scheduled to be drilled within five years of their initial disclosure. At December 31, 2010, our proved undeveloped reserves were 21,334 MBoe. During 2011, 4,184 MBoe or 19.6% of our proved

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undeveloped reserves were converted into proved developed reserves requiring $93.9 million of capital. The majority of the reserves converted to proved developed during 2011, 3,176 MBoe or 76%, resulted from our capital program in the Mid-Continent region. Executing the 2011 capital program in both the Rocky Mountain and Mid-Continent regions resulted in the addition of 10,190 MBoe in proved undeveloped reserves.

Internal controls over reserves estimation process

        We maintain an internal staff of petroleum engineers and geoscience professionals who ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers for their reserves estimation process. The technical person primarily responsible for overseeing the reserves process within the Company is Lynn E. Boone. Ms. Boone is our Senior Vice President, Planning & Reserves. Ms. Boone attended the Colorado School of Mines and graduated in 1982 with a Bachelor of Science degree in Chemical and Petroleum Refining Engineering. She attended the University of Oklahoma and graduated in 1985 with a Master of Science degree in Petroleum Engineering. Ms. Boone has been involved in evaluations and the estimation of reserves and resources for over 25 years. She has managed the technical reserve process at a company level for over ten years.

        Our technical team works with our banking syndicate members at least twice each year, for a valuation of our reserves by the banks in our lending group and their engineers in determining the borrowing base under our revolving credit facility.

Independent Reserve Engineers

        The reserves estimates for the year ended December 31, 2013 shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. ("NSAI"), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Dan Paul Smith and Mr. John Hattner. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. Mr. Smith is a Licensed Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Licensed Professional Geoscientist in the State of Texas, Geology, (License No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 20 years experience in the estimation and evaluation of reserves. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed 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; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

        The proved reserves estimate for the Company for the years ended December 31, 2011 and 2012 shown herein have been independently prepared by Cawley, Gillespie & Associates, Inc.; which was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within Cawley, Gillespie & Associates, Inc., the technical person primarily responsible for preparing the estimates shown herein was Zane Meekins. Mr. Meekins has been a petroleum engineering consultant at Cawley, Gillespie & Associates, Inc. since

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1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 24 years of practical experience in petroleum engineering, with over 22 years' experience in the estimation and evaluation of reserves. He graduated from Texas A&M University with a BS in Petroleum Engineering. Mr. Meekins 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.

Production, Revenues and Price History

        Oil and natural gas are commodities. The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Demand for oil and natural gas in the United States has increased dramatically over the last ten years. Beginning in 2010 there was a steady decline in natural gas prices but prices stabilized in the twelve month period ended December 31, 2013. The decline was caused by a global economic downturn and increased inventory of natural gas. Oil prices have steadily increased since 2010 and continued to do so during the twelve month period ended December 31, 2013. The increase was caused by increased demand coupled with unexpected global production outages.

        Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile and we expect that volatility to continue in the future. A substantial or extended decline in oil or natural gas prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and natural gas reserves that may be economically produced and our ability to access capital markets.

        The following table sets forth information regarding oil and natural gas production, realized prices, and production costs for the periods indicated. For additional information on price calculations, please

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see information set forth in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

Principal Customers

        Three of our customers, Plains Marketing LP, Lion Oil Trading & Transportation, Inc., and High Sierra Crude Oil & Marketing comprised 37%, 23%, and 15%, respectively, of our total revenue for the year ended December 31, 2013. No other single non-affiliated customer accounted for 10% or more of crude oil and natural gas sales in 2013. We believe the loss of any one customer would not have a material effect on our financial position or results of operations because there are numerous potential customers of our production.

Delivery Commitments

        We do not have any material delivery commitments.

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Productive Wells

        The following table sets forth the number of producing oil and natural gas wells in which we owned a working interest at December 31, 2013.

Acreage

        The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2013 for each of the areas where we operate along with the PV-10 values of each. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

Undeveloped acreage

        The following table sets forth the number of net undeveloped acres as of December 31, 2013 that will expire over the next three years by area unless production is established within the spacing units covering the acreage prior to the expiration dates:

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Drilling Activity

        The following table describes the exploratory and development wells we drilled and completed during the years ended December 31, 2013, 2012, and 2011.