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



Form 10-K


ý

 

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

For the fiscal year ended December 31, 2013

OR

o

 

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

Commission file number: 001-35371

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

Delaware
(State or other jurisdiction of
incorporation or organization)
  61-1630631
(I.R.S. Employer Identification No.)

410 17th Street, Suite 1400 Denver, Colorado
(Address of principal executive offices)

 

80202
(Zip Code)

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

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

(Title of Class)   (Name of Exchange)
Common Stock, par value $0.001 per share   New York Stock Exchange

         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.

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

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the 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

TABLE OF CONTENTS

 

Glossary of Certain Definitions

    iv  

 

PART I

       

Item 1.

 

Business

    1  

Item 1A.

 

Risk Factors

    29  

Item 1B.

 

Unresolved Staff Comments

    52  

Item 2.

 

Properties

    52  

Item 3.

 

Legal Proceedings

    53  

Item 4.

 

Mine Safety Disclosures

    53  

 

PART II

       

Item 5.

 

Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

    53  

Item 6.

 

Selected Financial Data

    55  

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

    57  

Item 7A.

 

Quantitative and Qualitative Disclosure about Market Risk

    75  

Item 8.

 

Financial Statements and Supplementary Data

    77  

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

    112  

Item 9A.

 

Controls and Procedures

    112  

Item 9B.

 

Other Information

    115  

 

PART III

       

Item 10.

 

Directors, Executive Officers and Corporate Governance

    115  

Item 11.

 

Executive Compensation

    115  

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

    115  

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

    115  

Item 14.

 

Principal Accountant Fees and Services

    115  

 

PART IV

       

Item 15.

 

Exhibits, Financial Statement Schedules

    116  

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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:

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        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:

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        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:

        "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.

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        "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:

Estimated Proved Reserves
  Crude
Oil
(MBbls)
  Natural
Gas
(MMcf)
  Natural
Gas
Liquids
(MBbls)
  Total
Proved
(MBoe)
 

Developed

                         

Rocky Mountain

    13,660     38,017         19,996  

Mid-Continent

    6,982     21,233     1,619     12,140  

California

    12             12  
                   

    20,654     59,250     1,619     32,148  
                   

Undeveloped

                         

Rocky Mountain

    18,461     63,229         28,999  

Mid-Continent

    4,431     17,135     1,317     8,604  

California

                 
                   

    22,892     80,364     1,317     37,603  
                   

Total Proved

    43,546     139,614     2,936     69,751  
                   
                   

 

 
   
   
   
   
  Production for
the Year Ended
December 31,
2013
   
   
 
 
  Estimated Proved Reserves at
December 31, 2013(1)
   
   
 
 
   
  Net Proved
Undeveloped
Drilling
Locations
as of
December 31,
2013
 
 
  Total
Proved
(MBoe)
  % of
Total
  % Proved
Developed
  PV-10
($ in MM)(2)
  Average
Net Daily
Production
(Boe/d)
  % of
Total
  Projected
2014 Capital
Expenditures
($ in millions)
 

Rocky Mountain

    48,995     70 %   41 % $ 908.9     10,618     66 % $ 500 - $540     161.3  

Mid-Continent

    20,744     30 %   59 %   318.1     5,554     34 %   75 - 85     93.2  

California

    12     0 %   100 %   0.2     47     0 %   0     0  
                                   

Total

    69,751     100 %   46 % $ 1,227.2     16,219     100 % $ 575 - $625     254.5  
                                   

(1)
Proved reserves and related future net revenue and PV-10 were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices for each of the preceding twelve months, which were $96.91 per Bbl WTI and $3.67 per MMBtu HH. Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $4.88 per Bbl of crude oil and an increase of $1.00 per MMBtu of natural gas.

(2)
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash 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 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. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating the Company and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. PV-10

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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.

 
  At December 31,  
Region/Field
  2013   2012   2011  
 
  (MMBoe)
 

Rocky Mountain

    49.1     32.4     21.4  

Wattenberg

    48.8     31.9     20.8  

North Park

    0.3     0.5     0.6  

Mid-Continent

    20.7     20.6     21.6  

Dorcheat Macedonia

    19.4     19.0     19.9  

McKamie Patton

    1.3     1.6     1.6  

Other

    0.0     0.0     0.1  

California

    0.0     0.0     0.7  
               

Total

    69.8     53.0     43.7  
               
               

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

 
  At December 31,  
 
  2013   2012   2011  

Reserve Data(1):

                   

Estimated proved reserves:

                   

Oil (MMBbls)

    43.6     30.2     24.6  

Natural gas (Bcf)

    139.6     118.5     93.0  

Natural gas liquids (MMBbls)

    2.9     3.1     3.6  

Total estimated proved reserves (MMBoe)(2)

    69.8     53.0     43.7  

Percent oil and liquids

    67 %   63 %   65 %

Estimated proved developed reserves:

                   

Oil (MMBbls)

    20.7     14.3     10.6  

Natural gas (Bcf)

    59.2     48.9     31.3  

Natural gas liquids (MMBbls)

    1.6     1.3     1.2  

Total estimated proved developed reserves (MMBoe)(2)

    32.2     23.8     17.0  

Percent oil and liquids

    69 %   66 %   69 %

Estimated proved undeveloped reserves:

                   

Oil (MMBbls)

    22.9     15.8     14.0  

Natural gas (Bcf)

    80.4     69.6     61.7  

Natural gas liquids (MMBbls)

    1.3     1.8     2.4  

Total estimated proved undeveloped reserves (MMBoe)(2)

    37.6     29.2     26.7  

Percent oil and liquids

    64 %   60 %   61 %

(1)
Proved reserves were calculated using prices equal to the twelve-month unweighted arithmetic average of the first-day-of-the-month prices for each of the preceding twelve months, which were $96.91 per Bbl WTI and $3.67 per MMBtu HH, $94.71 per Bbl WTI and $2.76 per MMBtu HH, $96.19 per Bbl WTI and $4.12 per MMBtu HH for the years ended December 31, 2013, 2012 and 2011 respectively. Adjustments were made for location and grade.

(2)
Determined using the ratio of 6 Mcf of natural gas being equivalent to one Bbl of crude oil.

        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:

 
  December 31,  
 
  2013   2012   2011  
 
  (in millions)
 

PV-10

  $ 1,227.2   $ 834.7   $ 794.0  

Present value of future income taxes discounted at 10%

    (301.9 )   (151.3 )   (127.8 )
               

Standardized Measure

  $ 925.3   $ 683.4   $ 666.2  
               
               

Proved Undeveloped Reserves

 
  Net Reserves, MBoe  
 
  At December 31,  
 
  2013   2012   2011  

Beginning of year

    29,192     26,652     21,334  

Converted to proved developed

    (3,047 )   (5,166 )   (4,184 )

Additions from capital program

    16,535     13,913     10,190  

Acquisitions (sales)

    1,779     (430 )    

Revisions (pricing and engineering)

    (6,856 )   (5,777 )   (688 )
               

End of year

    37,603     29,192     26,652  
               
               

        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.

 
  For the Years Ended December 31,  
 
  2013(1)   2012(1)   2011  

Oil:

                   

Total Production (MBbls)

    3,887.2     2,191.0     887.4  

Wattenberg Field

    2,775.6     1,190.8     400.8  

Dorcheat Macedonia Field

    925.2     789.5     359.8  

Average sales price (per Bbl), including derivatives(2)

  $ 88.82   $ 88.40   $ 85.51  

Average sales price (per Bbl), excluding derivatives(2)

  $ 91.84   $ 89.08   $ 89.67  

Natural Gas:

                   

Total Production (MMcf)

    9,975.9     5,473.2     2,773.1  

Wattenberg Field

    6,269.1     2,485.6     1,072.2  

Dorcheat Macedonia Field

    3,598.3     2,973.8     1,642.2  

Average sales price (per Mcf), including derivatives(2)

  $ 4.70   $ 3.76   $ 5.09  

Average sales price (per Mcf), excluding derivatives(2)

  $ 4.66   $ 3.62   $ 4.85  

Natural Gas Liquids:

                   

Total Production (MBbls)

    352.8     284.7     183.8  

Wattenberg Field

    10.2          

Dorcheat Macedonia Field

    342.6     284.7     183.8  

Average sales price (per Bbl), including derivatives

  $ 51.74   $ 55.54   $ 67.23  

Average sales price (per Bbl), excluding derivatives

  $ 51.74   $ 55.54   $ 67.23  

Oil Equivalents:

                   

Total Production (MBoe)

    5,902.7     3,387.9     1,533.4  

Wattenberg Field

    3,830.7     1,605.0     579.5  

Dorcheat Macedonia Field

    1,867.5     1,569.8     817.3  

Average daily production (Boe/d)

    16,171.8     9,257     4,201.1  

Wattenberg Field

    10,495.0     4,385.4     1,587.7  

Dorcheat Macedonia Field

    5116.4     4,289.1     2,239.2  

Average Production Costs (per Boe)

  $ 8.09   $ 9.06   $ 13.37  

(1)
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or held for sale as of December 31, 2013 and 2012.

(2)
Excludes ad valorem and severance taxes.

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.

 
  Oil   Natural
Gas(1)
  Total   Operated  
 
  Gross   Net   Gross   Net   Gross   Net   Gross   Net  

Rocky Mountain

    425     396.9             425     396.9     407     391.4  

Mid-Continent

    237     197.3             237     197.3     236     197.3  

California

    22     22.0             22     22.0     22     22.0  
                                   

Total

    684     616.2             684     616.2     665     610.7  
                                   
                                   

(1)
All gas production is associated gas from producing oil wells.

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.

 
  Developed Acres   Undeveloped
Acres
  Total Acres    
 
 
  Gross   Net   Gross   Net   Gross   Net   PV-10  

Rocky Mountain

    37,998     36,208     23,168     16,057     61,166     52,265   $ 908,857  

Wattenberg Field

    30,184     28,394     9,374     7,062     39,558     35,456     902,625  

Other Rocky Mountain

    7,814     7,814     13,794     8,995     21,608     16,809     6,232  

Mid-Continent

    5,397     4,130     6,846     5,128     12,243     9,258     318,139  

Dorcheat Macedonia Field

    4,117     2,894     2,129     1,304     6,246     4,198     280,571  

Other Mid-Continent

    1,280     1,236     4,717     3,824     5,997     5,060     37,568  

California

    480     480             480     480     229  
                               

Total

    43,875     40,818     30,014     21,185     73,889     62,003   $ 1,227,225  
                               
                               

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:

 
  Expiring 2014   Expiring 2015   Expiring 2016  
 
  Gross   Net   Gross   Net   Gross   Net  

Rocky Mountain

    320     574     2,631     2,674     2,561     1,233  

Mid-Continent

            137     122     1,099     696  

California

                         
                           

Total

    320     574     2,768     2,796     3,660     1,929  
                           
                           

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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.

 
  For the Years Ended December 31,  
 
  2013(1)   2012   2011  
 
  Gross   Net   Gross   Net   Gross   Net  

Exploratory

                                     

Productive Wells

                    53     52.9  

Dry Wells

    1     1     1     1          
                           

Total Exploratory

    1     1     1     1     53     52.9  
                           

Development

                                     

Productive Wells

    117     102.7     149     140.9     53     48.9  

Dry Wells

                         
                           

Total Development

    117     102.7     149     140.9     53     48.9  
                           

Total

    118     103.7     150     141.9     106     101.8  
                           
                           

        The following table describes the present drilling activities as of December 31, 2013.

 
  As of
December 31,
2013
 
 
  Gross   Net  

Exploratory

             

Rocky Mountain

         

Mid-Continent

         

California

         
           

Total Exploratory

         
           

Development

             

Rocky Mountain

    15     15  

Mid-Continent

    2     2  

California

         
           

Total Development

    17     17  
           

Total

    17     17  
           
           

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Capital Expenditure Budget

        Our anticipated 2014 capital budget is in a range of $575 million to $625 million which, at the midpoint of the range, represents an increase of 27% over capital spending during 2013 of $472 million. We plan to spend approximately $500 million to $540 million or 87% of our total 2014 budget in the Rocky Mountain region. Projected drilling, completion and infrastructure expenditures in the Wattenberg Field will account for approximately 99% of the capital allocated to the Rocky Mountain region. In the Mid-Continent region, we plan to spend approximately $75 million to $85 million during 2014. In total, we plan to spend approximately $545 million on operated drilling and completion activities with the remainder allocated to non-operated drilling and completion activities, field infrastructure and maintenance operations. The ultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, the success of our drilling results as the year progresses and changes in the borrowing base under our revolving credit facility.

Derivative Activity

        In addition to supply and demand, oil and gas prices are affected by seasonal, economic and geo-political factors that we can neither control nor predict. We attempt to mitigate a portion of our price risk through the use of derivative contracts.

        As of December 31, 2013, we had the following economic derivatives in place, which settle monthly:

Settlement
Period
  Derivative
Instrument
  Total Volumes
(Bbls/MMBtu
per day)
  Average
Fixed Price
  Average
Short Floor
Price
  Average
Floor
Price
  Average
Ceiling
Price
  Fair Market
Value of
Asset
(Liability)
 

Oil

                                         

1Q 2014

  Swap     3,133   $ 96.97                     $ (403,499 )

2Q 2014

  Swap     4,126   $ 96.20                       (288,370 )

3Q 2014

  Swap     3,870   $ 93.04                       (518,444 )

4Q 2014

  Swap     3,870   $ 93.04                       205,179  

1Q 2014

  Collar     5,617               $ 86.33   $ 97.09     (1,338,410 )

2Q 2014

  Collar     4,846               $ 86.55   $ 96.72     (1,252,787 )

3Q 2014

  Collar     4,326               $ 86.16   $ 96.57     (615,971 )

4Q 2014

  Collar     4,326               $ 86.16   $ 96.57     (68,724 )

2014

  3-Way Collar     1,000         $ 60.00   $ 85.00   $ 99.50     (303,314 )

2015

  3-Way Collar     4,500         $ 66.67   $ 83.33   $ 94.12     (782,385 )
                                         

                                    $ (5,366,725 )
                                         
                                         

Gas

                                         

2014

  3-Way Collar     15,000         $ 3.50   $ 4.00   $ 4.75   $ 122,173  

2015

  3-Way Collar     15,000         $ 3.50   $ 4.00   $ 4.75     (127,895 )
                                         

                                    $ (5,722 )
                                         
                                         

Total

                                    $ (5,372,447 )
                                         
                                         

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        As of the date of filing we had the following economic derivatives in place, which settle monthly:

Settlement
Period
  Derivative
Instrument
  Total Volumes
(Bbls/MMBtu
per day)
  Average
Fixed Price
  Average
Short Floor
Price
  Average
Floor
Price
  Average
Ceiling
Price
 

Oil

                                   

1Q 2014

  Swap     3,133   $ 96.97                    

2Q 2014

  Swap     4,126   $ 96.20                    

3Q 2014

  Swap     3,870   $ 93.04                    

4Q 2014

  Swap     3,870   $ 93.04                    

1Q 2014

  Collar     5,617               $ 86.33   $ 97.09  

2Q 2014

  Collar     4,846               $ 86.55   $ 96.72  

3Q 2014

  Collar     4,326               $ 86.16   $ 96.57  

4Q 2014

  Collar     4,326               $ 86.16   $ 96.57  

1Q 2014

  3-Way collar     1,000         $ 60.00   $ 85.00   $ 99.50  

2Q - 4Q 2014

  3-Way Collar     2,000         $ 65.00   $ 87.68   $ 99.75  

2015

  3-Way Collar     4,500         $ 66.67   $ 83.33   $ 94.12  

Gas

                                   

1Q 2014

  3-Way Collar     22,500         $ 3.56   $ 4.13   $ 4.78  

2Q - 4Q 2014

  3-Way Collar     30,000         $ 3.63   $ 4.21   $ 4.81  

2015

  3-Way Collar     15,000         $ 3.50   $ 4.00   $ 4.75  

        We do not apply hedge accounting treatment to any commodity derivative contracts. Settlements on these contracts and adjustments to fair value are shown as a component of derivative gain (loss). See Note 12—Derivatives to our consolidated financial statements for additional information regarding our derivative instruments.

Title to Properties

        Our properties are subject to customary royalty interest, overriding royalty interests, obligations incident to operating agreements, liens for current taxes and other industry-related constraints, including leasehold 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 have generally satisfactory title to or rights in all of our producing properties. Generally, we undergo thorough title review and receive title opinions from legal counsel before we commence drilling operations, subject to the availability and examination of accurate title records. Although in certain cases, title to our properties is subject to interpretation of multiple conveyances, deeds, reservations, and other constraints, we believe that none of these will materially detract from the value of our properties, from our interest therein or will materially interfere with the operation of our business.

Competition

        The oil and natural gas industry is highly competitive and we compete with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and natural gas, carry on refining operations and market the resultant products on a worldwide basis. The primary areas in which we encounter substantial competition are in locating and acquiring desirable leasehold acreage for our drilling and development operations, locating and acquiring attractive producing oil and gas properties, attracting and retaining qualified personnel, and obtaining transportation for the oil and gas we produce in certain regions. There is also competition between producers of oil and gas and other industries producing alternative energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the government of the United States; however, it is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may, however, substantially increase

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the costs of exploring for, developing or producing gas and oil and may prevent or delay the commencement or continuation of a given operation. The effect of these risks cannot be accurately predicted.

        Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 67% of our estimated proved reserves as of December 31, 2013 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. During the year ended December 31, 2013, the daily NYMEX WTI oil spot price ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl, and the NYMEX natural gas HH spot price ranged from a high of $4.52 per MMBtu to a low of $3.08 per MMBtu. As of the date of filing, we had commodity price derivative agreements for 2014 on approximately 60% of our anticipated production based on the mid-point of our guidance range of 23,000 Boe/d to 25,000 Boe/d.

Insurance Matters

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

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 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, and 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.

        Failure to comply with applicable laws 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. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission ("FERC"), and the courts. We cannot predict when or whether any such proposals or proceedings may become effective.

        We believe we are in substantial compliance with currently 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. However, current regulatory requirements may change, currently unforeseen incidents may occur or past non-compliance with laws or regulations may be discovered.

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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 ("ICA"), the Energy Policy Act of 1992 and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport 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.

        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.

        Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

        In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act ("NGPA") and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act ("NGA"), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

        FERC issued a series of orders in 1996 and 1997 to implement its open access policies. As a result, the interstate pipelines' traditional role as wholesalers of natural gas has been greatly reduced 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.

        The Domenici Barton Energy Policy Act of 2005 ("EP Act of 2005"), is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amends the NGA to add an anti-market manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC. The EP Act of 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC's civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation more

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accessible to natural gas services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC's NGA enforcement authority.

        Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting gas to point of sale locations. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although nondiscriminatory-take regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

        Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress.

        Our sales of natural gas are also subject to requirements under the Commodity Exchange Act ("CEA"), and regulations promulgated thereunder by the Commodity Futures Trading Commission ("CFTC"). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

        Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. 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.

        Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

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        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. The states in which we own and operate properties 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, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

        We own interests in properties located onshore in three U.S. states. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas.

        The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") was passed by Congress and signed into law in July 2010. The Dodd-Frank Act is designed to provide a comprehensive framework for the regulation of the over-the-counter derivatives market with the intent to provide greater transparency and reduction of risk between counterparties. The Dodd-Frank Act subjects swap dealers and major swap participants to capital and margin requirements and requires many derivative transactions to be cleared on exchanges. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end-users. In addition, in August 2012, the SEC issued a final rule under Section 1504 of the Dodd-Frank Act, Disclosure of Payment by Resource Extraction Issuers, which would have required resource extraction issuers, such as us, to file annual reports that provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals to each foreign government and the federal government. In July 2013, the U.S. District Court for the District of Columbia vacated the rule, and the SEC has announced it will not appeal the court's decision. However, the SEC may propose revised resource extraction payments disclosure rules applicable to our business.

Environmental, Health and Safety Regulation

        Our natural gas and oil exploration and production operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing safety and health, the discharge of materials into the environmental or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in

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certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

        The following is a summary of the more significant existing environmental and health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

        The Comprehensive Environmental Response, Compensation and Liability Act of 1980 ("CERCLA"), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict, joint and several 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, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances but we are not aware of any liabilities for which we may be held responsible that would materially and adversely affect us.

        The Resource Conservation and Recovery Act ("RCRA"), and analogous state laws, impose requirements on the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes certain drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA or state agencies under RCRA's less stringent nonhazardous solid waste provisions, state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

        We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In

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addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes were not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including groundwater contaminated by prior owners or operators), to pay for damages for the loss or impairment of natural resources, and to take measures to prevent future contamination from our operations.

        Pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation and storage of refined products and crude oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. The U.S. Department of Transportation ("DOT") has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

        There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. The Pipeline Safety, Regulatory Certainty, and Job Creation Act was signed into law in early 2012. In addition, the Pipeline and Hazardous Materials Safety Administration has issued new rules to strengthen federal pipeline safety enforcement programs.

        The Clean Air Act ("CAA") and comparable state laws and regulations restrict the emission of air pollutants from many sources, including oil and gas operations, and impose various monitoring 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 required air permits can significantly delay the development of certain oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues.

        For example, on August 16, 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 and National Emission Standards for Hazardous Air Pollutants 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 after October 15, 2012. However, 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 effective October 15, 2012 and from pneumatic controllers and storage

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vessels, effective October 15, 2013. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. The EPA issued revised rules in 2013 in response to some of these requests. For example, on September 23, 2013, the EPA published a final rule extending the compliance dates for certain groups of storage vessels to April 15, 2014 and April 15, 2015.

        In February 2014, the Colorado Air Quality Control Commission ("AQCC") is considering the adoption of new and revised air quality regulations that would impose stringent new requirements to control emissions from existing and new oil and gas facilities in Colorado. The proposed regulations being considered by the AQCC would impose new control, monitoring, recordkeeping, and reporting requirements on oil and gas operators in Colorado. For example, the AQCC will consider proposed Storage Tank Emission Management ("STEM") requirements for certain new and existing storage tanks. If adopted, the STEM requirements may require us to install costly emission control technologies at our new and existing well production facilities. The AQCC is also considering a Leak Detection and Repair ("LDAR") program for well production facilities and compressor stations. The proposed LDAR program primarily targets hydrocarbon (i.e., methane) emissions from the oil and gas sector in Colorado and would represent significant new use of state authority regarding these emissions.

        Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which costs could be significant. However, we do not currently believe that compliance with such requirements will have a material adverse effect on our operations.

        In response to findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration ("PSD") construction and Title V operating permit requirements for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions will also 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 our 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 from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations. We are monitoring GHG emissions from our operations in accordance with the GHG emissions reporting rule and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

        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. President Obama has indicated that climate change and GHG regulation is a significant priority for his second term. The President issued a Climate Action Plan in June 2013, calling for, among other things, a reduction in methane emissions from the oil and gas industry. Additionally, as discussed above, the state of Colorado intends to consider new air quality regulations in February 2014, targeting methane and ethane emissions from well production facilities and compressor stations.

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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 our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Severe limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce.

        Most recently, on October 15, 2013, the United States Supreme Court in Utility Air Regulatory Group v. EPA, No. 12-1146, granted a petition for certiorari to review the United States Court of Appeals for the District of Columbia Circuit's opinion and order upholding EPA's GHG-related regulations. The issue on review to the United States Supreme Court is whether EPA correctly determined that its regulation of GHGs from mobile sources triggered permitting requirements under the Clean Air Act for stationary sources of GHG emissions. The Court's decision is expected in Spring or Summer 2014, and could impact the scope of GHG regulation both at the federal and state levels.

        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 have an adverse effect on our exploration and production operations.

        The Federal Water Pollution Control Act or the Clean Water Act ("CWA") and analogous state laws impose restrictions and controls regarding the discharge of pollutants into certain surface waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or underlying state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited unless authorized by a permit issued by the U.S. Army Corps of Engineers ("Corps"). Obtaining permits has the potential to delay the development of natural gas and oil projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in certain quantities that may impose substantial potential liability for the costs of removal, remediation and damages. The EPA and Corps have recently submitted to the White House Office of Management and Budget for review a proposed rule that would define the scope of jurisdictional waters of the United States under the CWA. An expansive definition of such waters could affect our ability to operate in certain areas and may increase our costs of operations and permitting.

        Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as "SPCC plans," in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations, and further believe we are in substantial compliance with the terms thereof. As properties are acquired, we determine the need for new or updated SPCC plans and, where necessary, will develop or update such plans to implement physical and operation controls, the costs of which are not expected to be substantial.

        The federal Endangered Species Act restricts activities that may affect endangered and threatened species or their habitats. Some of our facilities may be located in areas that are designated as habitat for endangered or threatened species. The designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

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        We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (the "OSH Act"), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSH Act's hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens.

        Regulations relating to hydraulic fracturing.    We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Government authorities frequently add to those requirements, and both oil and gas development generally and hydraulic fracturing specifically are receiving increasing regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production.

        States have historically regulated oil and gas exploration and production activity, including hydraulic fracturing. State governments in the areas where we operate have adopted or are considering adopting additional requirements relating to hydraulic fracturing that could restrict its use in certain circumstances or make it more costly to utilize. Such measures may address any risk to drinking water, the potential for hydrocarbon migration and disclosure of the chemicals used in fracturing. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011 and 2013. Among other things, the updated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additional information regarding well bore integrity, publicly disclose the chemical ingredients used in hydraulic fracturing, increase the minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearby residents, and implement additional groundwater testing. The State is also considering new regulations for air emissions from oil and gas operations as well as potential legislation increasing the monetary penalties for regulatory violations. Any enforcement actions or requirements of additional studies or investigations by governmental authorities where we operate could increase our operating costs and cause delays or interruptions of our operations.

        The federal Safe Drinking Water Act ("SDWA") and comparable state statutes may restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids, primarily via disposal wells or enhanced oil recovery ("EOR") wells, is governed by federal or state regulatory authorities that, in some cases, include the state oil and gas regulatory or the state's environmental authority. The federal Energy Policy Act of 2005 amended the Underground Injection Control ("UIC"), provisions of the SDWA to expressly exclude certain hydraulic fracturing from the definition of "underground injection," but disposal of hydraulic fracturing fluids and produced water or their injection for EOR is not excluded. The U.S. Senate and House of Representatives have considered bills to repeal this SDWA exemption for hydraulic fracturing. If enacted, hydraulic fracturing operations could be required to meet additional federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, meet plugging and abandonment requirements, and provide additional public disclosure of chemicals used in the fracturing process as a consequence of additional SDWA permitting requirements.

        Federal agencies are also considering additional regulation of hydraulic fracturing. The EPA has prepared draft guidance for issuing underground injection permits that would regulate hydraulic

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fracturing using diesel fuel, where EPA has permitting authority under the SDWA; this guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing. In addition, on October 21, 2011, EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. EPA is also collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. EPA issued a progress report regarding the study in December 2012, which described generally the continuing focus of the study, but did not provide any data, findings, or conclusions regarding the safety of hydraulic fracturing operations. EPA intends to issue a final draft report for peer review and comment in 2014. The results of this study, which is still ongoing, could result in additional regulations, which could lead to operational burdens similar to those described above. EPA also has initiated a stakeholder and potential rulemaking process under the Toxic Substances Control Act ("TSCA") to obtain data on chemical substances and mixtures used in hydraulic fracturing, and recently published in the Federal Register a petition from national environmental advocacy groups seeking to include the oil and gas sector in the Toxics Release Inventory (TRI) reporting program established for many industries under TSCA. The United States Department of the Interior has also proposed a new rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. And the U.S. Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing.

        Apart from these ongoing federal and state initiatives, local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Some counties in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry and the State are challenging that ban—and the authority of local jurisdictions to regulate oil and gas development—in court. In November 2013, four other Colorado cities and counties passed voter initiatives either placing a moratorium on hydraulic fracturing or banning new oil and gas development. These initiatives too are the subject of pending legal challenge. While these initiatives cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for statewide referendums, especially in Colorado.

        At this time, it is not possible to estimate the potential impact on our business of recent state and local actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. The adoption of future federal, state or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products and services. We cannot assure you that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.

        Our use of hydraulic fracturing.    We use hydraulic fracturing as a means to maximize production of oil and gas from formations having low permeability such that natural flow is restricted. Fracture stimulation has been used for decades in both the Rocky Mountains and Mid-Continent. In the Rocky Mountains, other companies in the oil and gas industry have fracture stimulated tens of thousands of wells since the mid-1980s. We and our predecessor companies have completed over 373 fracture stimulations since acquiring assets in the Wattenberg Field in 1999. At our Dorcheat Macedonia property in the Mid-Continent region, fracture stimulation has been performed since the 1970s and has

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been used more universally since the early 1990s. We and our predecessor companies have completed over 140 fracture stimulations since acquiring our Dorcheat Macedonia properties in mid-2008. Typical hydraulic fracturing treatments are made up of water, chemical additives and sand. We utilize major hydraulic fracturing service companies who track and report all additive chemicals that are used in fracturing as required by the appropriate government agencies. Each of these companies fracture stimulate a multitude of wells for the industry each year. For as long as we have owned and operated properties subject to hydraulic fracturing, there have not been any material incidents, citations or suits related to fracturing operations or related to environmental concerns from fracturing operations.

        We periodically review our plans and policies regarding oil and gas operations, including hydraulic fracturing, in order to minimize any potential environmental impact. We adhere to applicable legal requirements and industry practices for groundwater protection. Our operations are subject to close supervision by state and federal regulators (including the Bureau of Land Management with respect to federal acreage), who frequently inspect our fracturing operations.

        We strive to minimize water usage in our fracture stimulation designs. Water recovered from our hydraulic fracturing operations is disposed of in a way that does not impact surface waters. We dispose of our recovered water by means of approved disposal or injection wells.

        Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies, including the Departments of Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency prepares an Environmental Assessment to evaluate the potential direct, indirect and cumulative impacts of a proposed project. If impacts are considered significant, the agency will prepare a more detailed environmental impact study that is made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This environmental impact assessment process has the potential to delay or limit, or increase the cost of, the development of natural gas and oil projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

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

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        Our properties located in Colorado are subject to the authority of the COGCC, as well as other state agencies. The COGCC recently approved new rules regarding minimum setbacks and groundwater monitoring that are intended to prevent or mitigate environmental impacts of oil and gas development and include the permitting of wells. The COGCC also recently approved new rules regarding reporting requirements for spills or releases of exploration and production waste or produced fluids. Depending on how these and any other new rules are applied, they could add substantial increases in well costs for our Colorado operations. The rules could also impact our ability and extend the time necessary to obtain drilling permits, which would create substantial uncertainty about our ability to meet future drilling plans and thus production and capital expenditure targets. The COGCC has also recently received a petition for rulemaking requesting that the COGCC promulgate certain rules that would require an evaluation of the impacts of oil and gas drilling on trust resources and human health according to the best available science before issuing any permits for oil and gas exploration and drilling. The COGCC intends to consider the petition in March 2014.

Employees

        As of December 31, 2013, we employed 236 people and also utilize the services of independent contractors to perform various field and other services. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

Offices

        As of December 31, 2013, we leased 57,454 square feet of office space in Denver, Colorado at 410 17th Street, where our principal offices are located. We also have leases for field offices in Houston, Texas, Bakersfield, California, Stamps, Arkansas and Kersey, Colorado totaling 12,682 square feet.

Available information

        We are required to file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Our filings with the SEC are also available to the public from commercial document retrieval services and at the SEC's website at http://www.sec.gov.

        Our common stock is listed and traded on the New York Stock Exchange under the symbol "BCEI." Our reports, proxy statements and other information filed with the SEC can also be inspected and copied at the New York Stock Exchange, 20 Broad Street, New York, New York 10005.

        We also make available on our website at http://www.bonanzacrk.com all of the documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Information contained on our website, other than the documents listed below, is not incorporated by reference into this Annual Report on Form 10-K.

Item 1A.    Risk Factors.

        Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial also may adversely affect us.

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Risks Related to Our Business

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

        The price we receive for our oil and, to a lesser extent, natural gas, heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas 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:

        Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market based prices. Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our reserves. See Our exploration, development and exploitation projects require substantial capital expenditures. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our proved reserves. See also 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 below.

        Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 67% of our estimated proved reserves as of December 31, 2013 were oil and natural gas liquids, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile and we expect this volatility to continue. During the year ended December 31, 2013, the daily NYMEX WTI oil spot price ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl and the NYMEX natural gas Henry Hub spot price ranged from a high of $4.52 per MMBtu to a low of $3.08 per MMBtu.

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        As of December 31, 2013, we had commodity price derivative agreements on approximately 9,526 Bbls/d and 4,500 Bbls/d of oil hedged with average minimum prices of $89.48/Bbl and $83.33/Bbl in 2014 and 2015, respectively.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

        Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see 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 below. Our cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

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.

        The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K. See Estimated Proved Reserves under Item 1, Part I of this Annual Report on Form 10-K for information about our estimated oil and natural gas reserves and the PV-10 (a non-GAAP financial measure) as of December 31, 2013, 2012 and 2011.

        In order 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.

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The extent, quality and reliability of these data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise particularly as they relate to new technologies being employed such as the combination of hydraulic fracturing and horizontal drilling.

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

There is a limited amount of production data from horizontal wells completed in the Wattenberg Field. As a result, reserve estimates associated with horizontal wells in this Field are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same Field.

        Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontal drilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been utilized by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small. Until a greater number of horizontal wells have been completed in the Wattenberg Field, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year over year basis due to the transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories. We cannot assure you that any such variance would not be material and any such variance could have a material and adverse impact on our cash flows and results of operations.

Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the regions where we operate.

        Oil and natural gas operations are adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife, particularly in the Rocky Mountain region in both cases. In certain areas on federal lands, drilling and other oil and natural gas activities can only be conducted during limited times of the year. These restrictions limit our ability to operate in those areas and can potentially intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

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 new SEC requirements for the years ended December 31, 2013, 2012 and 2011, we based the estimated discounted future net revenues from our proved reserves on the unweighted arithmetic average of the first-day-of-the-month commodity prices (after adjustment for location and quality differentials) for the preceding 12 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:

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

        Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report on Form 10-K. If oil and natural gas prices declined by 10% per Bbl and Mcf then our PV-10 as of December 31, 2013 would decrease by approximately 20% or $242.6 million. PV-10 is a non-GAAP financial measure. Please refer to Estimated Proved Reserves under Item 1, Part 1 of this Annual Report on Form 10-K for management's discussion of this non-GAAP financial measure.

If oil and natural gas 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, which 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.

We intend to pursue the further development of our properties in the Wattenberg Field through horizontal drilling. Horizontal drilling operations can be more operationally challenging and costly relative to our historic vertical drilling operations. Our limited operational history with drilling and completing horizontal wells may make us more susceptible to cost overruns and lower results.

        Horizontal drilling is generally more complex and more expensive on a per well basis than vertical drilling. As a result, there is greater risk associated with a horizontal well drilling program. Risks associated with a horizontal drilling program include, but are not limited to,

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Any of these risks could materially and adversely impact the success of our horizontal drilling program and thus our cash flows and results of operations.

        The results of our drilling in new or emerging formations, such as horizontal drilling in the Niobrara formation, are more uncertain initially than drilling results in areas or using technologies that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history, and consequently we are less able to predict future drilling results in these areas.

        Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, limited takeaway capacity, or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

Our ability to produce natural gas and oil economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use at a reasonable cost and in accordance with applicable environmental rules.

        The hydraulic fracture stimulation process on which we depend to produce commercial quantities of oil and natural gas requires the use and disposal of significant quantities of water. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, and all of which could have an adverse effect on our operations and financial condition.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

        Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves or anticipated production volumes.

        Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash flows used in investing activities, excluding derivative cash settlements, were $453.9 million and $304.6 million (including $25.8 million and $13.9 million for the acquisition of oil and gas properties and contractual obligations for land acquisitions) related to capital and exploration expenditures for the years ended December 31, 2013 and 2012, respectively. The mid-point of our capital expenditure budget for 2014 is approximately

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$600 million, with approximately $545 million allocated for operated drilling and completion activities. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

        A significant improvement in oil and gas prices could result in an increase in our capital expenditures. We intend to finance our future capital expenditures primarily through cash flows provided by operating activities and borrowings under our revolving credit facility. Our financing needs may require us to alter or increase our capitalization substantially through the issuance of additional equity securities, debt securities or the sale of non-strategic assets. The issuance of additional debt or equity may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. In addition, upon the issuance of certain debt securities (other than on a borrowing base redetermination date), our borrowing base under our revolving credit facility would be reduced.

        Our cash flows provided by operating activities and access to capital are subject to a number of variables, including:

If the borrowing base under our revolving credit facility or our revenues decrease as a result of lower oil or natural gas 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 on terms favorable to us, or at all. If cash generated by operations or cash available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our oil and natural gas reserves, and could adversely affect our business, financial condition and results of operations.

Increased costs of capital could adversely affect our business.

        Recent and 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. Our business and operating results can be harmed by factors such as the terms and cost of capital, increases in interest rates or a reduction in credit rating. 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.

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We may experience difficulty in achieving and managing future growth.

        We have experienced growth in the past primarily through the expansion of our drilling program and acquisitions. Future growth may place strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial position and results of operations. Our ability to grow depends on a number of factors, including:

Our inability to achieve or manage growth may adversely affect our financial position and results of operations.

        Our ability to pursue our growth strategy may be hindered if we are not able to attract, develop and retain executives and other qualified employees. As a result, we are required to continue to invest in operational, financial and management information systems to attract, retain, motivate and effectively manage our employees.

Concentration of our operations in a few core areas may increase our risk of production loss.

        Our assets and operations are concentrated in two core areas: the Wattenberg Field in Colorado and the Dorcheat Macedonia Field in southern Arkansas. These core areas currently provide approximately 97% of our current production and the vast majority of our development projects. Beginning in 2012, we initiated a non-core divestiture program to focus our portfolio through the sale of certain non-core assets in California, with one property remaining to be sold as of December 31, 2013. As a result of these portfolio changes, our operations and production are more concentrated.

        The Wattenberg and Dorcheat Macedonia Fields represent 65% and 32%, respectively, of our 2013 total sales volumes. Disruption of our business in either of these Fields, such as from an accident, natural disaster or other event, would result in a greater impact on our production profile, cash flows and overall business plan than if we operated in a larger number of areas.

        We do not maintain business interruption (loss of production) insurance for our oil and gas producing properties. Loss of production or limited access to reserves in either of our core operating areas could have a significant negative impact on our cash flows and profitability.

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We are dependent on third party pipeline, trucking and rail systems to transport our production and, in the Wattenberg Field, gathering and processing systems to prepare our production. These systems have limited capacity and at times have experienced service disruptions. Curtailments, disruptions or lack of availability in these systems interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect our cash flow and results of operations.

        Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The marketability of our oil and natural gas and production, particularly from our wells located in the Wattenberg Field, depends in part on the availability, proximity and capacity of gathering, processing, pipeline, trucking and rail systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system, or lack of contracted capacity on such systems. 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, excessive pressures, maintenance, weather, field labor issues or disruptions in service. Curtailments and disruptions in these systems may last from a few days to several months. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. These risks are greater for us than for some of our competitors because our operations are focused on areas where there is currently a substantial amount of development activity, which increases the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the resulting increases in production. For example, the gas gathering systems serving the Wattenberg Field recently experienced high line pressures reducing capacity and causing gas production to either be shut in or flared. In addition, we might voluntarily curtail production in response to market conditions. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities or lack of availability of transport, would interfere with our ability to market the oil and natural gas we produce, and could materially and adversely affect our cash flow and results of operations, and the expected results of our drilling program.

        Currently, there are no natural gas pipeline systems that service wells in the North Park Basin, which is prospective for the Niobrara formation. In addition, we are not aware of any plans to construct a facility necessary to process natural gas produced from this basin. If neither we nor a third party constructs the required pipeline system and processing facility, we may not be able to fully develop our resources in the North Park Basin.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.

        Approximately 54% of our total proved reserves were classified as proved undeveloped as of December 31, 2013. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the value 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.

Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

        In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our current proved reserves will decline as reserves

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are produced and, therefore, our level of production and cash flows will be affected adversely unless we conduct successful exploration and development activities or acquire properties containing proved reserves. Thus, our future oil and natural gas production and, therefore, our cash flow and income are highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in any specific amount of additional proved reserves or that we will be able to drill productive wells at acceptable costs.

        According to estimates included in our December 31, 2013 proved reserve report, if, on January 1, 2014, we had ceased all drilling and development, including recompletions, refracs and workovers, then our proved developed producing reserves base would decline at an annual effective rate of 53% during the first year. If we fail to replace reserves through drilling, our level of production and cash flows will be affected adversely.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks, including those related to our hydraulic fracturing operations.

        Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

        Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

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        At two of our Arkansas properties, we produce a small amount of gas from seven operated wells where we have identified the presence of H2S at levels that would be hazardous in the event of an uncontrolled gas release or unprotected exposure. In addition, our operations in Arkansas and Colorado are susceptible to damage from natural disasters such as flooding, wildfires or tornados, which involve increased risks of personal injury, property damage and marketing interruptions. The occurrence of one of these operating hazards may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration and development, or could result in a loss of our properties.

        As is customary in the gas and oil industry, we maintain insurance against some, but not all, of these potential risks and losses. Although we believe the coverage and amounts of insurance that we carry are consistent with industry practice, we do not have insurance protection against all risks that we face, because we choose not to insure certain risks, insurance is not available at a level that balances the costs of insurance and our desired rates of return, or actual losses exceed coverage limits. 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. In addition, pollution and environmental risks generally are not fully insurable. 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.

        Because hydraulic fracturing activities are part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. We may not have coverage if the operator is unaware of the pollution event and unable to report the "occurrence" to the insurance company within the required time frame. Nor do we have coverage for gradual, long-term pollution events.

        Under certain circumstances, we have agreed to indemnify third parties against losses resulting from our operations. Pursuant to our surface leases, we typically indemnify the surface owner for clean-up and remediation of the site. As owner and operator of oil and gas wells and associated gathering systems and pipelines, we typically indemnify the drilling contractor for pollution emanating from the well, while the contractor indemnifies us against pollution emanating from its equipment.

Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

        We describe some of our drilling locations and our plans to explore those drilling locations in this Annual Report on Form 10-K. Our drilling locations are in various stages of evaluation, ranging from a location that is ready to drill to a location that will require substantial additional evaluation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

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Our potential drilling location inventories are scheduled to be developed over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

        Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of December 31, 2013, a significant portion of our drilling program targets probable and possible reserves with only 305 gross (255 net) of our approximately 1,950 identified potential future gross drilling locations attributed to proved undeveloped reserves. These potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including uncertainty in the level of reserves, the availability of capital to us and other participants, seasonal conditions, regulatory approvals, oil and natural gas prices, availability of permits, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to existing SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. These rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.

        The terms of our oil and gas leases stipulate that the lease will terminate if not held by production, rentals, or operations. As of December 31, 2013, the majority of our acreage in Arkansas was held by unitization, production, or drilling operations and therefore not subject to lease expiration. As of December 31, 2013, 16,057 net acres of our properties in the Rocky Mountain region, specifically 7,062 acres in the Wattenberg Field and 8,995 acres in the North Park Basin, were not held by production. For these properties, if production in paying quantities is not established on units containing these leases during the next year, then 574 net acres will expire in 2014, 2,674 net acres will expire in 2015, and 1,233 net acres will expire in 2016. If our leases expire, we will lose our right to develop the related properties.

We may incur losses as a result of title deficiencies.

        The existence of a title deficiency can diminish the value of an acquired leasehold interest and can adversely affect our results of operations and financial condition. Title insurance covering mineral leasehold interests is not generally available. In certain situations we may rely upon a land professional's careful examination of public records prior to purchasing or leasing a mineral interest. Once a specific mineral or leasehold interest has been acquired, we typically defer the expense of obtaining further title verification by a practicing title attorney until the drilling block needs approval to drill. We do not always perform curative work to correct deficiencies in the marketability of the title; however, we currently have compliance and control measures to ensure any associated business risk is approved by the appropriate company authority. In cases involving more serious title deficiencies, all or part of a mineral or leasehold interest may be determined to be invalid or unleased, and, as a result, the target area may be deemed to be undrillable until owners can be contacted and curative performed to perfect title. Certain title deficiencies may also result in litigation from time to time. Additional title issues are present in our Southern Arkansas operations. Significant delays in the title examination process are possible due to, among other challenges, the large volume of instruments contained in abstracts, poor indexing at the county clerk and recorder's office, the misfiling of instruments, instruments with missing or inadequate legal descriptions and unclear conveyance terms.

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We face various risks associated with the trend toward increased activism against oil and gas exploration and development activities.

        Opposition toward oil and gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, environmental compliance and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as the development of oil or gas shale plays. For example, environmental activists continue to advocate for increased regulations or bans on shale drilling in the United States, even in jurisdictions that are among the most stringent in their regulation of the industry. Future activist efforts could result in the following:

        We may need to incur significant costs associated with responding to these initiatives. Complying with any resulting additional legal or regulatory requirements that are substantial and not adequately provided for could have a material adverse effect on our business, financial condition and results of operations.

Our operations are subject to health, safety and environmental laws and regulations that may expose us to significant costs and liabilities.

        Our oil and natural gas exploration, production and processing operations are subject to stringent and complex federal, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment and the protection of the environment. These laws and regulations may impose on our operations numerous requirements, including the obligation to obtain a permit before conducting drilling or underground injection activities; restrictions on the types, quantities and concentration of materials that may 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 and criminal penalties; the imposition of investigatory or remedial obligations; the issuance of injunctions

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limiting or preventing some or all of our operations; delays in granting permits, or even the cancellation of leases.

        There is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use and disposition of hydraulic fracturing fluids, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we may be liable regardless of whether we 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 us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. 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 reclamation or disposal and other private parties may be able to sue 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 sites we operate are located near current or former third-party oil and natural gas operations or facilities, and there is a risk that historic 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 material handling, emission, waste management or cleanup requirements could require us to make significant expenditures to attain and maintain compliance or may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.

        We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Government authorities frequently add to those requirements, and both oil and gas development generally and hydraulic fracturing specifically are receiving increasing regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production.

        Recently, the EPA issued final rules that establish new air emission controls for natural gas processing operations, as well as for oil and natural gas production. Among other things, the latter rules cover the completion and operation of hydraulically fractured gas wells and associated equipment. After several parties challenged the new air regulations in court, the EPA reconsidered certain requirements and is evaluating whether reconsideration of other issues is warranted. At this point, we cannot predict the final regulatory requirements or the cost to comply with such air regulatory requirements.

        Some activists have attempted to link hydraulic fracturing to various environmental problems, including potential adverse effects to drinking water supplies as well as migration of methane and other hydrocarbons. As a result, the federal government is studying the environmental risks associated with hydraulic fracturing and evaluating whether to adopt additional regulatory requirements. For example, the EPA has commenced a multi-year study of the potential impacts of hydraulic fracturing on drinking water resources, and the draft results are expected to be released for public and peer review in 2014 . In addition, on October 21, 2011, the EPA announced its intention to propose regulations by 2014 under the federal Clean Water Act to regulate wastewater discharges from hydraulic fracturing and other natural gas production. The EPA also has prepared draft guidance for issuing underground injection permits that would regulate hydraulic fracturing using diesel fuel, where EPA has permitting

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authority under the Safe Drinking Water Act ("SDWA"); this guidance eventually could encourage other regulatory authorities to adopt to permitting and other restrictions on the use of hydraulic fracturing. The U.S. Department of Interior, moreover, has proposed new rules for hydraulic fracturing activities on federal lands that, in general, would cover disclosure of fracturing fluid components, well bore integrity, and handling of flowback water. And the U.S. Occupational Safety and Health Administration has proposed stricter standards for worker exposure to silica, which would apply to use of sand as a proppant for hydraulic fracturing.

        In the United States Congress, bills have been introduced that would amend the SDWA to eliminate an existing exemption for certain hydraulic fracturing activities from the definition of "underground injection," thereby requiring the oil and natural gas industry to obtain SDWA permits for fracturing not involving diesel fuels, and to require disclosure of the chemicals used in the process. If adopted, such legislation could establish an additional level of regulation and permitting at the federal level, but some form of chemical disclosure is already required by most oil and gas producing states. At this time, it is not clear what action, if any, the United States Congress will take on hydraulic fracturing.

        Apart from these ongoing federal initiatives, state governments where we operate have moved to impose stricter requirements on hydraulic fracturing and other aspects of oil and gas production. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011 and 2013. Among other things, the updated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additional information regarding well bore integrity, publicly disclose the chemical ingredients used in hydraulic fracturing, increase the minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearby residents, and implement additional groundwater testing. The State is also considering new regulations for air emissions from oil and gas operations as well as potential legislation increasing the monetary penalties for regulatory violations.

        Even local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations. Some counties in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry and the State are challenging that ban—and the authority of local jurisdictions to regulate oil and gas development—in court. In November 2013, four other Colorado cities and counties passed voter initiatives either placing a moratorium on hydraulic fracturing or banning new oil and gas development. These initiatives too are the subject of pending legal challenge. While these initiatives cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for statewide referendums, especially in Colorado.

        The adoption of future federal, state or local laws or implementing regulations imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products and services. We cannot assure you that any such outcome would not be material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.

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Climate change laws and regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

        There is a growing belief that human-caused (anthropogenic) emissions of greenhouse gases ("GHG") may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHG have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services and the demand for and consumption of our products and services (due to potential changes in both costs and weather patterns).

        In December 2009, the EPA determined that atmospheric concentrations of carbon dioxide, methane and certain other GHG 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 has proposed or adopted various regulations under the Clean Air Act to address GHG. Among other things, the EPA began limiting emissions of GHG from new cars and light duty trucks beginning with the 2012 model year. In addition, the EPA has published a final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration, or "PSD," and Title V permitting programs, pursuant to which these permitting requirements have been "tailored" to apply to certain "major" stationary sources of GHG emissions in a multi-step process, with the largest major sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions will be required to meet emissions limits that are based on the "best available control technology," which will be established by the permitting agencies on a case-by-case basis. The EPA also adopted regulations requiring the reporting of GHG emissions from specific categories of higher GHG emitting sources in the United States, including certain oil and natural gas production facilities, which include certain of our operations, beginning in 2012 for emissions occurring in 2011. Information in such report may form the basis for further GHG regulation. Further, the EPA is evaluating strategies for reducing air emissions of methane from oil and gas operations. The EPA's GHG rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities.

        Moreover, Congress has from time to time considered adopting legislation to reduce emissions of GHG or promote the use of renewable fuels. As an alternative, some proponents of GHG controls have advocated mandating a national "clean energy" standard. In 2011, for example, President Obama encouraged Congress to adopt a goal of generating 80% of U.S. electricity from "clean energy" by 2035 with credit for renewable and nuclear power and partial credit for clean coal and "efficient natural gas." Because of the lack of any comprehensive federal legislative program expressly addressing GHG, there currently is a great deal of uncertainty as to how and when additional federal regulation of GHG might take place and as to whether the EPA should continue with its existing regulations in the absence of more specific Congressional direction.

        In the meantime, many states already have taken such measures, which have included renewable energy standards, development of GHG emission inventories or cap and trade programs. Cap and trade programs typically work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of available allowances reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time.

        The adoption of legislation or regulatory programs to reduce emissions of GHG could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. If we are unable to recover or pass through a significant level of our costs related to complying with climate

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change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHG could have an adverse effect on our business, financial condition and results of operations.

        Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG 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 our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and 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.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

        Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

If we fail to retain our existing senior management or technical personnel or attract qualified new personnel, such failure could adversely affect our operations.

        To a large extent, we depend on the services of our senior management and technical personnel. The loss of the services of our senior management, technical personnel, or any of the vice presidents of the Company, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

        Effective January 31, 2014, Michael R. Starzer, retired from his position as President and Chief Executive Officer and Marvin M. Chronister, a current Board member, is serving as Interim President and Chief Executive Officer until a permanent replacement is identified. We are in the process of completing a comprehensive search for a permanent Chief Executive Officer, however there can be no assurance that we will be able to identify and hire a qualified candidate in a timely manner. Our ability to attract, select and hire a permanent Chief Executive Officer candidate may prove difficult, take more time than anticipated, and be costly. This may require other senior management to divert part of their attention from their primary duties, which could have an adverse effect on our business or operations.

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Similarly, our business could be adversely affected if we are unable to attract and retain qualified senior management, including a permanent Chief Executive Officer.

We recorded substantial stock-based compensation expense in 2013, and we are likely to incur additional stock-based compensation expense related to our future grants of stock, which may impact our operating results for the foreseeable future.

        We incurred stock-based compensation expense in 2013 in the amount of $12.6 million compared to $4.5 million in 2012. Our compensation expenses are likely to increase in the future as compared to our historical expenses because of the costs associated with our stock-based incentive plans. These additional expenses will adversely affect our net income. We cannot determine the actual amount of these new stock-related compensation and benefit expenses at this time, because applicable accounting practices generally require that they be based on the fair market value of the options or shares of common stock at the date of the grant; however, we expect them to be significant. We will recognize expenses for restricted stock and stock option awards we grant generally over the vesting period of such awards.

Our derivative activities could result in financial losses or could reduce our income.

        To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we currently, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We have not designated any of our derivative instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

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

        In addition, these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas and may expose us to cash margin requirements.

Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

        The Dodd-Frank Act, which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act also establishes margin requirements and certain transaction clearing and trade execution requirements. On October 18, 2011, the Commodities Futures Trading Commission (the "CFTC") approved regulations to set position limits for certain futures and option contracts in the major energy markets, which were successfully challenged in federal district court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association and largely vacated by the court. The CFTC has filed a notice of appeal with respect to this ruling. Under CFTC final rules promulgated under the Dodd-Frank Act, we believe our derivatives activity will qualify for the non-financial, commercial end-user exception, which exempts derivatives intended to hedge or mitigate commercial risk from the mandatory swap clearing

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requirement. The Dodd-Frank Act may also require us to comply with margin requirements in our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation 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 Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivative as a result of the Dodd-Frank Act and regulations, our results of operations may be more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations 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 leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payment on our Senior Notes.

        As of December 31, 2013, we had $500 million of outstanding 6.75% Senior Notes ("Senior Notes"), no borrowings outstanding under our revolving credit facility and $181 million of cash and cash equivalents. We intend to fund our capital expenditures through our cash flow from operations and borrowings under our revolving credit facility, but may seek additional debt financing. Our level of indebtedness could affect our operations in several ways, including the following:

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Our revolving credit facility and the indenture governing the Senior Notes have restrictive covenants that could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

        Our revolving credit facility and the indenture governing the Senior Notes contain restrictive covenants that limit our ability to engage in activities that may be in our long-term best interests.

        Our ability to borrow under our revolving credit facility is subject to compliance with certain financial covenants, including the maintenance of certain financial ratios, including a minimum current ratio, a maximum leverage ratio and a minimum interest coverage ratio.

        In addition, our revolving credit facility and the indenture governing the Senior Notes contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to:

        Our failure to comply with these covenants could result in an event of default that, if not cured or waived, could result in the acceleration of all of our indebtedness. We would not have sufficient working capital to satisfy our debt obligations in the event of an acceleration of all or a significant portion of our outstanding indebtedness.

        We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us by the restrictive covenants contained in our revolving credit facility and the indenture governing the Senior Notes. Our ability to comply with the financial ratios and financial condition tests under our revolving credit facility may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities.

Borrowings under our credit facility are limited by our borrowing base, which is subject to periodic redetermination.

        The borrowing base under our credit facility is redetermined at least semi-annually, and the lenders holding 662/3% of the aggregate commitments or we may request one additional

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redetermination in each six-month period. Redeterminations are based upon a number of factors, including commodity prices and reserve levels. In addition, our lenders have substantial flexibility to reduce our borrowing base due to subjective factors. Upon a redetermination, we could be required to repay a portion of our bank debt to the extent our outstanding borrowings at such time exceed the redetermined borrowing base. We may not have sufficient funds to make such repayments, which could result in a default under the terms of the facility and an acceleration of the loans thereunder requiring us to negotiate renewals, arrange new financing or sell significant assets, all of which could have a material adverse effect on our business and financial results.

The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.

        Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates. We had approximately $57.5 million in receivables from oil and gas sales at December 31, 2013.

        We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. This concentration of customers may impact our overall credit risk since these entities may be similarly affected by changes in economic and other conditions. For the year ended December 31, 2013, sales to Lion Oil Trading & Transport, Inc., Plains Marketing LP, and High Sierra Crude Oil & Marketing accounted for approximately 23%, 37%, and 15%, respectively, of our total sales. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Failure to maintain effective internal controls could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could in turn have a material adverse effect on our business and stock price.

        Our management does not expect that our internal controls and disclosure controls will prevent all possible error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, in the Company have been detected. The design of any system of controls is based in part upon the likelihood of future events, and there can be no assurance that any design will succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions or the degree of compliance with its policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection. If we are unable to maintain effective internal controls, our business and operating results could be harmed or investors could lose confidence in our financial reports, which could have a material adverse effect on our business and stock price.

Compliance with the reporting and disclosure requirements of a public company under the Exchange Act, the NYSE rules and the requirements of the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act requires a substantial amount of management's time and will continue to increase our costs.

        As a public company with listed securities, we must comply with laws, rules, regulations and requirements of the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act, related regulations of the SEC and the requirements of the New York Stock Exchange ("NYSE"), among other laws, rules, regulations and requirements. Complying with these laws, rules, regulations and requirements occupies

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a significant amount of time of our board of directors and management and will continue to significantly increase our costs and expenses.

We may be involved in legal proceedings that may result in substantial liabilities.

        Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

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

        There have been proposals for legislative changes that, if enacted into law, would eliminate certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. Any such changes in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition, results of operations and cash flow.

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption or financial loss.

        The oil and gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and distribution activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation and process and record financial and operating data. Pipelines, refineries, power stations and distribution points for both fuels and electricity are becoming more interconnected by computer systems. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. Our technologies, systems, networks and those of our vendors, suppliers and other business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient.

        Although to date we have not experienced any material losses relating to cyber-attacks, we may suffer such losses in the future. We may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

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Risks Relating to our Common Stock

We do not intend to pay, and we are currently prohibited from paying, dividends on our common stock and, consequently, our stockholders' only opportunity to achieve a return on their investment is if the price of our stock appreciates.

        We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, we are currently prohibited from making any cash dividends pursuant to the terms of our revolving credit facility and our Senior Notes. Consequently, our stockholders' only opportunity to achieve a return on their investment in us will be if the market price of our common stock appreciates, which may not occur, and the stockholder sells their shares at a profit. There is no guarantee that the price of our common stock will ever exceed the price that the stockholder paid.

The market price and trading volume of our common stock may be volatile and our stock price could decline.

        The trading price of shares of our common stock has from time to time fluctuated widely and in the future may be subject to similar fluctuations. The trading price of our common stock may be affected by a number of factors, including our operating results, financial condition, drilling activities, general conditions in the oil and natural gas exploration and development industry, general economic conditions, the securities markets and the risk factors set forth in this annual report, which are incorporated herein by reference.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute our current stockholders' ownership in us.

        If our existing stockholders sell a large number of shares of our common stock in the public market, the market price of our common stock could decline significantly. In addition, the perception in the public market that our existing stockholders might sell shares of common stock could depress the market price of our common stock, regardless of the actual plans of our existing stockholders. Her Majesty the Queen in Right of Alberta, in her own capacity and as trustee/nominee for certain Alberta pension clients ("HMQ"), owns 7,587,859 shares, or approximately 18.83% of our total outstanding shares. HMQ is party to a registration rights agreement with us. Pursuant to this agreement, we have agreed to effect the registration of shares held by HMQ if itso requests or if we conduct other offerings of our common stock. In addition, we may issue additional shares of our common stock, including securities that are convertible into or exchangeable for, or that represent the right to receive, shares of common stock or substantially similar securities, which may result in dilution to our stockholders. In addition, our stockholders may be further diluted by future issuances under our equity incentive plans.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if such acquisition or merger may be in our stockholders' best interests.

        Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

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        Delaware law prohibits us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

Alberta Investment Management Corporation may be deemed to beneficially own or control a significant portion of our common stock, giving them a substantial influence over corporate transactions and other matters. Their interests and the interests of the parties on whose behalf they invest may conflict with our other stockholders, and the concentration of ownership of our common stock by such stockholders will limit the influence of public stockholders.

        AIMCo, a Canadian corporation and investment manager to HMQ and certain Alberta pension funds, may be deemed to beneficially own, control or have substantial influence over approximately 18.83% of our outstanding common stock. West Face Capital and AIMCo, on behalf of HMQ and certain Alberta pension funds, have entered into an investment management agreement pursuant to which West Face Capital has the right to vote the shares of our common stock held by HMQ. Accordingly, West Face may exert significant influence over our board of directors and substantially influence the outcome of stockholder votes. Even if the investment management agreement between West Face Capital and AIMCo were to be terminated, AIMCo, on behalf of HMQ, would have the ability to exert significant influence over the Company.

        A concentration of ownership in AIMCo's clients would allow such stockholders to influence, directly or indirectly and subject to applicable law, significant matters affecting us, including the following:

        Such a concentration of ownership may have the effect of delaying, deterring or preventing a change in control, a merger, consolidation, takeover or other business combination, and could discourage a potential acquirer from making a tender offer or otherwise attempting to obtain control of us, which could in turn have an adverse effect on the market price of our common stock. The significant ownership interest of HMQ could also adversely affect investors' perceptions of our corporate governance.

Item 1B.    Unresolved Staff Comments.

        None.

Item 2.    Properties.

        The information required by Item 2. is contained in Item 1. Business and is incorporated herein by reference.

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Item 3.    Legal Proceedings.

        From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other gas and oil producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities. As of the date of this filing, there are no material pending or overtly threatened legal actions against us that of which we are aware.

Item 4.    Mine Safety Disclosures.

        Not applicable.


PART II

Item 5.    Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

        Market for Registrant's Common Equity.    Our common stock is listed on the NYSE under the symbol "BCEI".

        The following table sets forth the high and low intra-day sales prices per share of our common stock as reported on the NYSE.

 
  High   Low  

2013

             

1st Quarter

  $ 42.36   $ 28.23  

2nd Quarter

    40.40     32.06  

3rd Quarter

    51.32     34.67  

4th Quarter

    57.47     41.78  

2012

             

1st Quarter

  $ 22.25   $ 12.62  

2nd Quarter

    22.66     14.52  

3rd Quarter

    24.40     15.00  

4th Quarter

    29.03     20.83  

        Holders.    As of February 24, 2014, there were approximately 172 registered holders of our common stock.

        Dividends.    We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility and the indenture governing our Senior Notes restrict the payment of cash dividends on our common stock. We currently intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.

        On February 24, 2014, the last sale price of our common stock, as reported on the NYSE, was $47.44 per share.

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        Issuer Purchases of Equity Securities.    The following table contains information about our acquisition of equity securities during the year ended December 31, 2013:

 
  Total
Number of
Shares
Purchased(1)
  Average Price
Paid per
Share
  Total Number of
Shares
Purchased as Part of
Publicly Announced
Program
  Maximum
Number of
Shares that May
Be Purchased
Under Programs
 

January 1, 2013 - January 31, 2013

                 

February 1, 2013 - February 28, 2013

    74,994   $ 34.79          

March 1, 2013 - March 31, 2013

    622   $ 39.29          

April 1, 2013 - April 30, 2013

    4,719   $ 35.73          

May 2, 2013 - May 31, 2013

                 

June 1, 2013 - June 30, 2013

                 

July 1, 2013 - July 31, 2013

    1,097   $ 39.95          

August 1, 2013 - August 31, 2013

    5,327   $ 38.16          

September 1, 2013 - September 30, 2013

    2,412   $ 45.91          

October 1, 2013 - October 31, 2013

    1,593   $ 48.52          

November 1, 2013 - November 30, 2013

    3,979   $ 51.94          

December 1, 2013 - December 31, 2013

    13,496   $ 44.26          
                   

Total

    108,239   $ 37.34          
                   
                   

(1)
Represent shares that employees surrendered back to us that equaled in value the amount of taxes needed for payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.

        Sale of Unregistered Securities.    We had no sales of unregistered securities during the quarter ended December 31, 2013.

        Stock Performance Graph.    The following performance graph shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to liabilities under that section and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

        The following graph compares, the cumulative total stockholder return for the Company's common stock, the Standard and Poor's 500 Stock Index (the "S&P 500 Index") and the Standard and Poor's 500 Oil & Gas Exploration & Production Index ("S&P O&G E&P Index"). The measurement points in the graph below are December 14, 2011 (the first trading day of our common stock on the NYSE) and each fiscal quarter thereafter through December 31, 2013. The graph assumes that $100 was invested on December 14, 2011 in the common stock of Bonanza Creek Energy, Inc., the S&P 500 Index and the S&P O&G E&P Index and assumes reinvestment of any dividends. The stock price performance on the following graph is not necessarily indicative of future stock price performance.

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GRAPHIC

Item 6.    Selected Financial Data.

        The selected historical financial data should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations and financial statements and the notes to those financial statements in Item 8, Part II of this Annual Report on Form 10-K.

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        The following tables set forth selected historical financial data of the Company as of and for the period indicated.

 
  Period from
Inception
(December 23,
2010) to
December 31,
2010)
  Year Ended
December 31,
2011
  Year Ended
December 31,
2012
  Year Ended
December 31,
2013
 
 
  (in thousands, except per share amounts)
 

Statement of Operations Data:

                         

Revenues:

                         

Oil sales

  $ 1,200   $ 79,568   $ 195,175   $ 357,001  

Natural gas sales

    207     13,442     19,795     46,490  

Natural gas liquids and CO2 sales

    213     12,714     16,235     18,369  
                   

Total revenues

    1,620     105,724     231,205     421,860  
                   

Operating expenses:

                         

Lease operating

    419     18,253     30,695     47,771  

Severance and ad valorem taxes

    66     5,918     13,674     27,203  

Exploration

        878     10,715     4,213  

Depreciation, depletion and amortization

    436     28,014     66,202     140,176  

Impairment of oil and gas properties(2)

        623     611      

General and administrative

    324     13,164     26,922     42,864  

Employee stock compensation(1)

        4,449     4,483     12,638  
                   

Total operating expenses

    1,245     71,299     153,302     274,865  
                   

Income from operations

    375     34,425     77,903     146,995  

Other income (expense):

                         

Interest expense

    (58 )   (4,017 )   (4,133 )   (21,972 )

Derivative gain (loss)

    (561 )   (2,799 )   925     (12,472 )

Other loss

        (110 )   (133 )   (43 )
                   

Total other expense

    (619 )   (6,926 )   (3,341 )   (34,487 )
                   

Income (loss) from continuing operations before taxes

    (244 )   27,499     74,562     112,508  

Income tax benefit (expense)

    90     (12,890 )   (29,991 )   (42,926 )
                   

Income (loss) from continuing operations

    (154 )   14,609     44,571     69,582  
                   

Discontinued operations(3)

                         

Loss from operations associated with oil and gas properties held for sale (including impairments in 2011, and 2012 of $3.4 million and $1.6 million, respectively)(2)

    (13 )   (3,610 )   (927 )   (644 )

Gain on sale of oil and gas properties

            4,192      

Income tax (expense) benefit

    5     1,692     (1,313 )   246  
                   

Income (loss) from discontinued operations

    (8 )   (1,918 )   1,952     (398 )
                   

Net income (loss)

  $ (162 ) $ 12,691   $ 46,523   $ 69,184  
                   
                   

Basic net income (loss) per common share

                         

Income from continuing operations per share

  $   $ 0.49   $ 1.12   $ 1.73  

Income (loss) from discontinued operations per share

  $   $ (0.06 ) $ 0.05   $ (0.01 )

Net income per share

  $   $ 0.43   $ 1.17   $ 1.72  

Basic weighted-average common shares outstanding

    29,123     29,324     39,052     39,337  

Diluted net income (loss) per common share

                         

Income from continuing operations per share

  $   $ 0.49   $ 1.12   $ 1.72  

Income (loss) from discontinued operations per share

  $   $ (0.06 ) $ 0.05   $ (0.01 )

Net income per share

  $   $ 0.43   $ 1.17   $ 1.71  

Diluted weighted-average commons shares outstanding

    29,123     29,324     39,052     39,404  

(1)
In connection with our IPO, the Company distributed 243,945 fully vested shares of former Class B common stock, previously held in trust, to our employees and recorded a $4.1 million stock-based compensation charge. In addition the Company distributed the remaining 10,000 shares of our former Class B common stock to our executives and employees. In connection with our IPO, the 10,000 shares of our former Class B common stock converted into 437,787 shares of restricted common stock, vesting over a three year period. In connection with our Long Term Incentive Plan ("LTIP"), the Company granted 310,439 and 731,034 shares of restricted common stock during 2013 and 2012, respectively, which vest over a three year period, and 41,622 shares of performance share units during 2013, which vest entirely after a three-year measurement period. The Company expects to recognize compensation expense relating to these grants during the years ended December 31, 2014, 2015, and 2016 of approximately $11.0 million, $5.7 million, and $1.5 million, respectively.

(2)
The impairment for 2011 was related to steam flooding results in our legacy California assets that were lower than expected and the impairment of one non-core field in Southern Arkansas was related to the loss of a lease. The impairments for 2012 were related to one non-core field in Southern Arkansas and our legacy California assets that were written down to their expected sales price.

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(3)
The results of operation and impairment loss related to non-core properties in California sold in 2012 or held for sale have been reflected as discontinued operations. Please refer to Note 3—Discontinued Operations to our consolidated financial statements in Item 8, Part II of this Annual Report on Form 10-K.

 
  As of December 31,  
 
  2010   2011   2012   2013  
 
  (in thousands)
 

Balance Sheet Data:

                         

Cash and cash equivalents

  $   $ 2,090   $ 4,268   $ 180,582  

Property and equipment, net (excludes assets held for sale)

    481,374     618,229     943,175     1,267,249  

Oil and gas properties held for sale, net of accumulated depreciation, depletion, and amortization

    15,208     9,896     582     360  

Total assets

    516,104     664,349     1,002,490     1,545,935  

Long term debt, including current portion:

                         

Credit facility

    55,400     6,600     158,000      

Senior Notes, net of unamortized premium

                508,847  

Total stockholders' equity

    356,380     527,982     578,518     656,028  

 

 
  Inception
(December 23,
2010) to
December 31, 2010
  Year Ended
December 31, 2011
  Year Ended
December 31, 2012
  Year Ended
December 31, 2013
 
 
  (in thousands)
 

Selected Cash Flow Data:

                         

Net cash provided by (used in) operating activities

  $ (1,586 ) $ 60,627   $ 157,636   $ 307,015  

Net cash (used in) investing activities

    (864 )   (161,926 )   (305,277 )   (465,223 )

Net cash provided by financing activities

        103,389     149,819     334,522  

Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

Executive Summary

        We are a Denver-based exploration and production company focused on the extraction of oil and associated liquids-rich natural gas in the United States. Our predecessors were founded in 1999 and we went public in December 2011. Our shares of common stock are listed for trading on the NYSE under the symbol "BCEI."

        Our oil and liquids-weighted assets are concentrated primarily in the Wattenberg Field in Colorado, part of the Rocky Mountain region, and the Dorcheat Macedonia Field in southern Arkansas, part of the Mid-Continent region. In addition, we own and operate oil-producing assets in other fields in Arkansas and the North Park Basin in Colorado. During the second quarter of 2012, we began the divestiture process for all of our California properties, with one property remaining to be sold as of December 31, 2013. Under generally accepted accounting principles, the results of operations for the California properties are presented as discontinued operations and are included unless otherwise noted. 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 continue to contribute to the development of our sizable inventory of projects. We maintain a high working interest in our properties.

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Financial and Operating Highlights

        Our 2013 financial results included:

        We delivered significant growth in 2013. Operational highlights for 2013 included:

Senior Management Change

        Effective January 31, 2014, the Company's President and CEO, Michael R. Starzer, retired from his position and as a member of the Company's Board. The Board has begun a search for a new President and CEO. During this interim period, Marvin M. Chronister, a current member of the Board, will act as interim President and CEO. Mr. Chronister has over 38 years of oil and gas industry experience and has served on the Company's Board since March 2011.

Outlook for 2014

        Because the global economic outlook, central bank policies and commodity price environment are uncertain, we have planned a flexible capital spending program. We estimate our total capital expenditures for 2014 to be in the range of $575 million to $625 million, allocating approximately 87% to the Wattenberg Field and 13% to southern Arkansas. Actual capital expenditures are subject to a number of factors, including economic conditions and commodity prices, and the Company may reduce or augment the capital budget as appropriate. This capital investment is expected to produce 2014

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average sales volumes of 23,000 Boe/d to 25,000 Boe/d, while maintaining a strong oil and liquids profile.

Results of Operations

        The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto contained in Item 8, Part II of this Annual Report on Form 10-K. Comparative results of operations for the period indicated are discussed below.

        The table below presents revenues, sales volumes, and average sales prices for the years ended December 31, 2013 and 2012:

 
  For the Years Ended December 31,  
 
  2013(3)   2012(3)   Change   Percent
Change
 
 
  (in thousands, except percentages)
 

Revenues:

                         

Crude oil sales

  $ 357,001   $ 195,175   $ 161,826     83 %

Natural gas sales

    46,490     19,795     26,695     135 %

Natural gas liquids sales

    18,256     15,811     2,445     15 %

CO2 sales

    113     424     (311 )   (73 )%
                     

Product revenues

  $ 421,860   $ 231,205   $ 190,655     82 %
                     
                     

Sales volumes:

                         

Crude oil (MBbls)

    3,887.2     2,191.0     1,696.2     77 %

Natural gas (MMcf)

    9,975.9     5,473.2     4,502.7     82 %

Natural gas liquids (MBbls)

    352.8     284.7     68.1     24 %
                     

Crude oil equivalent (MBoe)(1)

    5,902.7     3,387.9     2,514.8     74 %
                     
                     

Average Sales Prices (before derivatives)(2):

                         

Crude oil (per Bbl)

  $ 91.84   $ 89.08   $ 2.76     3 %

Natural gas (per Mcf)

  $ 4.66   $ 3.62   $ 1.04     29 %

Natural gas liquids (per Bbl)

  $ 51.74   $ 55.54   $ (3.80 )   (7 )%

Crude oil equivalent (per Boe)(1)

  $ 71.45   $ 68.12   $ 3.33     5 %

Average Sales Prices (after derivatives)(2):

                         

Crude oil (per Bbl)

  $ 88.82   $ 88.40   $ 0.42     0 %

Natural gas (per Mcf)

  $ 4.70   $ 3.76   $ 0.94     25 %

Natural gas liquids (per Bbl)

  $ 51.74   $ 55.54   $ (3.80 )   (7 )%

Crude oil equivalent (per Boe)(1)

  $ 69.53   $ 67.91   $ 1.62     2 %

(1)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil. Excludes CO2 sales.

(2)
The derivatives economically hedge the price we receive for crude oil and natural gas.

(3)
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or held for sale as of December 31, 2013 and 2012.

        Revenues increased by 82%, to $421.9 million for the year ended December 31, 2013 compared to $231.2 million for the year ended December 31, 2012 due primarily to increased production, but higher crude oil and natural gas prices also contributed. Oil, natural gas, and natural gas liquids production increased 77%, 82%, and 24%, respectively, during the year ended December 31, 2013, when compared to the year ended December 31, 2012. During the period from January 1, 2013 through December 31, 2013, we drilled and completed 73 gross (67.2 net) wells in the Rockies and 45 gross (36.5 net) wells in southern Arkansas. The increased volumes are a direct result of the $447.1 million expended for drilling and completion during the year ended December 31, 2013. Oil volumes increased by 77% in 2013, and the sales price increased 3% from $89.08 per barrel during the year ended December 31,

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2012 to $91.84 per barrel during the year ended December 31, 2013, which together accounted for the $161.8 million increase in revenues. Natural gas volumes increased by 82% in 2013, and were aided by an increase in sales price of 29% from $3.62 per Mcf to $4.66 per Mcf for these one year periods, which together accounted for an additional $26.7 million of the increase in revenues. Natural gas liquid volumes increased by 24% in 2013, but were offset by a sales price decline of 7% from $55.54 per Bbl to $51.74 per Bbl for the comparable period. Our Wattenberg Field natural gas is sold without processing into dry gas and NGLs, and therefore, sells at a premium due to its high BTU content.

        The table below presents operating expenses and per Boe data for the years ended December 31, 2013 and 2012:

 
  For the Years Ended December 31,  
 
  2013(1)   2012(1)   Change   Percent
Change
 
 
  (in thousands, except percentages)
 

Expenses:

                         

Lease operating

  $ 47,771   $ 30,695   $ 17,076     56 %

Severance and ad valorem taxes

    27,203     13,674     13,529     99 %

Exploration

    4,213     10,715     (6,502 )   (61 )%

Depreciation, depletion and amortization

    140,176     66,202     73,974     112 %

Impairment of oil and gas properties

        611     (611 )   (100 )%

General and administrative

    55,502     31,405     24,097     77 %
                     

Operating expenses

  $ 274,865   $ 153,302   $ 121,563     79 %
                     
                     

Expenses per Boe:

                         

Lease operating

  $ 8.09   $ 9.06   $ (0.97 )   (11 )%

Severance and ad valorem taxes

    4.61     4.04     0.57     14 %

Exploration

    0.71     3.16     (2.45 )   (78 )%

Depreciation, depletion and amortization

    23.75     19.54     4.21     22 %

Impairment of oil and gas properties

        0.18     (0.18 )   (100 )%

General and administrative

    9.40     9.27     0.13     1 %
                     

Operating expenses

  $ 46.56   $ 45.25   $ 1.31     3 %
                     
                     

(1)
Amounts reflect results for continuing operations and exclude results for discontinued operations related to non-core properties in California sold or held for sale as of December 31, 2013 and 2012.

        Lease operating expense.    Our lease operating expenses increased $17.1 million, or 56%, to $47.8 million for the year ended December 31, 2013 from $30.7 million for the year ended December 31, 2012 and decreased on an equivalent basis from $9.06 per Boe to $8.09 per Boe. The increase in lease operating expense was related to the increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2012 but did not come on line until February of 2013. During the year ended December 31, 2013, three of the largest components of lease operating expenses; well servicing, compression, and pumping increased $6.8 million, $2.6 million, and $2.3 million, respectively, over the comparable period in 2012. Gas plant operating expense, which is a component of lease operating expense, increased $3.8 million, or 45%, to $12.2 million for the year ended December 31, 2013 from $8.4 million for the year ended December 31, 2012. While our lease operating expense per Boe decreased due to higher production from our lower cost horizontal wells in the Wattenberg Field we were still impacted by high gas gathering pipeline pressures and emission compliance standards which resulted in production that was less than anticipated. In Southern Arkansas the replacement of essential gas plant processing equipment cost approximately $400,000 to install. Our newly constructed gas plant is not yet running at full capacity; however the operating cost of said gas plant does not vary based on capacity causing our

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lease operating expense per Boe to be higher than it would be if the gas plant were operating at capacity.

        Severance and ad valorem taxes.    Our severance and ad valorem taxes increased $13.5 million, or 99%, to $27.2 million for the year ended December 31, 2013 from $13.7 million for the year ended December 31, 2012. The increase was primarily related to a 74% increase in production volumes with a corresponding 5% increase in average sales price per Boe for the year ended December 31, 2013 as compared to the year ended December 31, 2012.

        General and administrative.    Our general and administrative expense increased $24.1 million, or 77%, to $55.5 million for the year ended December 31, 2013 from $31.4 million for the year ended December 31, 2012 and increased on an equivalent basis from $9.27 per Boe to $9.40 per Boe. During the year ended December 31, 2013, wages and benefits, stock-based compensation, and professional service expenses were $13.2 million, $8.2 million, and $2.7 million higher, respectively, than the year ended December 31, 2012. The increase in wages and stock-based compensation is primarily due to increased headcount and incentive compensation, which is tied directly to improved Company results. The majority of the increase in professional services relates to outsourced land work performed during the year relating to our expanded drilling program.

        Depreciation, depletion and amortization.    Our depreciation, depletion and amortization expense increased $74.0 million, or 112%, to $140.2 million for the year ended December 31, 2013 from $66.2 million for the year ended December 31, 2012. Our depreciation, depletion, and amortization expense per Boe increased $4.21, to $23.75 for the year ended December 31, 2013 as compared to $19.54 for the year ended December 31, 2012. The increase in depreciation, depletion, and amortization expense is primarily due to a 55% increase in depreciable assets at December 31, 2013 when compared to the same period in 2012. The increase per Boe is related to a larger increase in production of 74% versus the corresponding increase in proved developed reserves of 35%.

        Exploration.    Our exploration expense decreased $6.5 million, or 61%, to $4.2 million in the year ended December 31, 2013 from $10.7 million in the year ended December 31, 2012. During 2013, we spent $1.5 million on seismic and 3D data acquisitions for the Wattenberg Field, wrote-off one exploratory dry hole totaling $630,000 and $1.7 million on an expired non-core lease in the North Park Basin, and paid delay rentals in the amount of $300,000. During 2012, we wrote-off three exploratory dry holes in the North Park Basin amounting to $8.4 million, we spent $2.0 million on a seismic acquisition project in the North Park Basin, and paid delay rentals in the amount of $300,000.

        Interest expense.    Our interest expense increased $17.9 million, or 437%, to $22.0 million for the year ended December 31, 2013 from $4.1 million for the year ended December 31, 2012. The increase for the year ended December 31, 2013 compared to the year ended December 31, 2012 is primarily related to the issuance of $500 million in 6.75% Senior Notes during 2013. Interest expense on the Senior Notes in 2013 was $17.0 million, of which $798,000 related to the amortization of debt issuance costs related to the Senior Notes offering, offset by the amortization of the premium on the Senior Notes of $153,000. Interest expense on our revolving credit facility was $4.1 million for the year ended December 31, 2013. The average outstanding long-term debt balance during the year ended December 31, 2013 was $306.0 million as compared to $74.7 million for the year ended December 31, 2012.

        Derivative gain (loss).    Our derivative loss increased $13.4 million, or 1,449%, to $12.5 million for the year ended December 31, 2013 from a $924,000 gain for the comparable period in 2012. The loss incurred on derivative contracts during 2013 was primarily the result of realized prices being greater than the contract prices. Please refer to Note 12—Derivatives in Item 8, Part II of this Annual Report on Form 10-K for additional discussion.

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        Income tax expense.    Our estimate for federal and state income taxes for the year ended December 31, 2013 was $42.9 million from continuing operations as compared to $30.0 million for the year ended December 31, 2012. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. Our effective tax rate for the year ended December 31, 2013 was 38.2% as compared to 40.2% for the year ended December 31, 2012, these rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

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

        The table below presents revenues, sales volumes, and average sales prices for the years ended December 31, 2012 and 2011:

 
  For the Year Ended December 31,  
 
  2012(3)   2011   Change   Percent
Change
 

Revenues (In thousands, except percentages)

                         

Crude oil sales

  $ 195,175   $ 79,568   $ 115,607     145 %

Natural gas sales

    19,795     13,442     6,353     47 %

Natural gas liquids sales

    15,811     12,358     3,453     28 %

CO2 sales

    424     356     68     19 %
                     

Product revenues

  $ 231,205   $ 105,724   $ 125,481     119 %