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TABLE OF CONTENTS
Item 8. Financial Statements and Supplementary Data.

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE 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, 2012

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. o

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o   Accelerated filer ý   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 29, 2012, based upon the closing price of $16.63 of the registrant's common stock as reported on the New York Stock Exchange, was approximately $138,010,440. Excludes approximately 31,713,010 million shares of the registrant's common stock held by current executive officers, directors and stockholders that the registrant has concluded are affiliates of the registrant.

         Number of shares of registrant's common stock outstanding as of February 28, 2013: 40,040,430

Documents Incorporated By Reference:

         Portions of the registrant's definitive proxy statement for its 2013 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2012, are incorporated by reference into Part III of this report for the year ended December 31, 2012.

   


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BONANZA CREEK ENERGY, INC.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2012

TABLE OF CONTENTS

 

Glossary of Certain Definitions

  v

PART I

Item 1.

 

Business

  1

Item 1A.

 

Risk Factors

  27

Item 1B.

 

Unresolved Staff Comments

  49

Item 2.

 

Properties

  49

Item 3.

 

Legal Proceedings

  49

Item 4.

 

Mine Safety Disclosures

  50

PART II

Item 5.

 

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

  50

Item 6.

 

Selected Financial Data

  52

Item 7.

 

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

  59

Item 7A.

 

Quantitative and Qualitative Disclosure about Market Risk

  78

Item 8.

 

Financial Statements and Supplementary Data

  81

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  109

Item 9A.

 

Controls and Procedures

  109

Item 9B.

 

Other Information

  111

PART III

Item 10.

 

Directors, Executive Officers and Corporate Governance

  111

Item 11.

 

Executive Compensation

  111

Item 12.

 

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

  111

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  111

Item 14.

 

Principal Accountant Fees and Services

  111

PART IV

Item 15.

 

Exhibits, Financial Statement Schedules

  112

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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" 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:

        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

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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.

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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.

        "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.

        "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,

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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" A resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

        "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.

        "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 feature.

        "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.

        "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.

        "Original oil in place" Refers to the oil in place before the commencement of production. Oil in place is distinct from oil reserves, which are the technically and economically recoverable portion of oil volume in the reservoir.

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        "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.

        "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 reserves that are less certain to be recovered than probable reserves.

        "Probable reserves" Those 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.

        "Production Costs" Production costs are the costs of activities that involve lifting oil and natural gas to the surface and gathering, treating, processing, and storage in the field.

        "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.

        The area of the reservoir considered as proved includes:

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

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        Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

        "Proved undeveloped reserves" or "PUD" Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are schedule to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

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

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

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

Overview

        Bonanza Creek Energy, Inc. ("Bonanza Creek" or, together with our consolidated subsidiaries, the "Company," "we," "us," or "our") 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 (Rocky Mountain region) and the Dorcheat Macedonia Field in southern Arkansas (Mid-Continent region). In addition, we own and operate oil-producing assets in the North Park Basin in Colorado and one non-core Field in California. 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 99.3% of our proved reserves with an average working interest of 87.3%, providing us with significant control over the rate of development of our asset base.

        As of December 31, 2012, we accumulated 79,843 gross (69,184 net) leasehold acres across our properties. We are currently focused on the horizontal development of significant resource potential from the Niobrara and Codell formations in the Wattenberg Field, investing approximately 82% of our 2013 capital budget in this project. The remaining 18% of our 2013 budget is allocated primarily to the vertical development of the Dorcheat Macedonia Field in southern Arkansas, targeting the oily Cotton Valley sands. We also plan to drill development wells in the McKamie Patton Field and finalize an expansion of our gas processing facilities in Arkansas. 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 2012, we drilled 150 operated wells and 9 non-operated wells and had 4 development wells in progress as of December 31, 2012. The resulting production rates achieved by this program increased sales volumes by 115% over the previous year to 9,403 Boe/d of which 73% was crude oil and natural gas liquids. The Rocky Mountain region contributed 49% and the Mid-Continent region contributed 50% to total production, while California was responsible for 1%. Our average net daily production rate during December 2012 was 12,468 Boe/d, a 105% increase over December 2011.

        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. During 2012, we sold a majority of our properties in California, for approximately $9.3 million in aggregate.

        Cawley, Gillespie & Associates, Inc., our independent reserve engineers, estimated our net proved reserves as of December 31, 2012, to be as follows:

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

Developed

                         

Rocky Mountain

    8,365     31,646         13,639  

Mid-Continent

    5,934     17,296     1,345     10,162  

California

    31             31  
                   

Undeveloped

                         

Rocky Mountain

    10,847     47,692         18,796  

Mid-Continent

    4,982     21,914     1,762     10,396  

California

                 
                   

Total Proved

    30,159     118,548     3,107     53,024  
                   

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  Production for
the Year Ended
December 31,
2012
   
   
 
 
  Estimated Proved Reserves at
December 31, 2012(1)
   
  Net Proved
Undeveloped
Drilling
Locations
as of
December 31,
2012
 
 
  Average
Net Daily
Production
(Boe/d)
   
  Projected
2013 Capital
Expenditures
($ in millions)
 
 
  Total
Proved
(MBoe)
  % of
Total
  % Proved
Developed
  PV-10
($ in MM)(2)
  % of
Total
 

Rocky Mountain

    32,435     61 %   42 % $ 450.2     4,568     49 %   324     144.6  

Mid-Continent

    20,558     39 %   49 %   383.9     4,689     50 %   70     99.9  

California

    31     0 %   100 %   0.6     146     1 %   0     0  
                                   

Total

    53,024     100 %   45 % $ 834.7     9,403     100 %   394     244.5  
                                   

(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 $94.71 per Bbl WTI and $2.757 per MMBtu of HH. Adjustments were then made for location, grade, transportation, gravity, and Btu content, which resulted in a decrease of $3.67 per Bbl of crude oil and an increase of $1.02 per MMBtu of natural gas respectively.

(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 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. 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 differs from Standarized Measure of Discounted Future Net Cash Flows ("Standardized Measure") because it does not include the effect of future income taxes. See "—Reconciliation of PV-10 to Standardized Measure" below.

Our History

        Bonanza Creek Energy, Inc. was incorporated on December 2, 2010 pursuant to the laws of the State of Delaware. On December 23, 2010, in connection with an investment from Project Black Bear LP ("Black Bear"), an entity advised by West Face Capital Inc. ("West Face Capital") and certain clients of Alberta Investment Management Corporation ("AIMCo"), we acquired Bonanza Creek Energy Company, LLC ("BCEC") and Holmes Eastern Company, LLC ("HEC"), which transactions we refer to as our "Corporate Restructuring." For more information, see Note 1 to our consolidated financial statements in Item 8 of Part II of this Annual Report on Form 10-K. We completed the initial public offering of our common stock in December 2011 (our "IPO") pursuant to which 10,000,000 shares of our common stock were sold.

Acquisition

        On August 1, 2012, we leased approximately 5,600 net acres from the State of Colorado in the core of our Wattenberg Field position for a total purchase price of approximately $57 million, of which

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$12 million was payable at closing and the balance is payable in equal annual lease payments over the next four years. This development will be facilitated by the Company's existing relationships with surface landowners allowing for efficiencies in future development.

Our Business Strategies

        Our goal is to increase stockholder value by investing capital to increase our production, proved reserves and cash flow. We intend to accomplish this by focusing on the following key strategies:

Our Competitive Strengths

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

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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.

        We believe the Wattenberg Field to be the most prospective area for the Niobrara formation evidenced by, to date, a high level of industry activity and successful drilling results.

        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, 2012, our Wattenberg position consisted of approximately 33,000 gross (31,000 net) acres. During 2012, we had a net increase of approximately 1,500 net acres in the Wattenberg Field, which includes an increase in net acreage of approximately 6,000 acres through acquisitions and leasing in our core area and a reduction of approximately 4,500 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.

        The Wattenberg Field is now primarily developed for the Niobrara and Codell formations using horizontal drilling and multi-stage fracture stimulation techniques. We are developing the Niobrara "B" Bench at 80-acre spacing while testing the Niobrara "C" bench and further down spacing. We have also begun testing the Codell formation, which is prospective on approximately 15,000 of our net acres.

        Our estimated proved reserves at December 31, 2012 in the Wattenberg Field were 31,943 MBoe. As of December 31, 2012, we had a total of 266 producing wells, of which 46 were horizontal wells, and our average daily production during 2012 was approximately 4,385 Boe/d, of which 51% came from horizontal wells. Our average daily production for the month of December 2012 was 7,133 Boe/d. Our working interest for all producing wells averages approximately 93% and our net revenue interest is approximately 77%.

        We continue to expand our proved reserves in this area by drilling non-proved horizontal locations. During 2012, we drilled 35 horizontal wells and 72 vertical wells. We estimate our capital expenditures in the Wattenberg Field for 2013 will be $324 million, which includes drilling 64 horizontal wells in the

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Niobrara "B" Bench, four horizontal wells in the Niobrara "C" Bench and four horizontal wells in the Codell sandstone. This drilling program includes 12 proved locations and 60 non-proved locations.

        Our horizontal well program delivered strong production performance in 2012. We drilled 32 4,000 foot horizontal wells in the Niobrara "B" Bench at an average well cost of $4.5 million. Of these wells, 26 produced for longer than 30 days for an average 30-day initial production rate of 514 Boe/d at 76% crude oil, while 21 wells produced for longer than 60 days for an average 60-day production rate of 395 Boe/d at 74% crude oil. We drilled one horizontal well in the Codell formation for approximately $4.5 million, which had a 30-day average production rate of 370 Boe/d at 81% crude oil, and one horizontal well in the Niobrara "C" Bench for approximately $4.4 million, which delivered a 30-day average production rate of 444 Boe/d at 79% crude oil. Our extended reach lateral into the Niobrara "B" Bench was drilled in 2012 and cost approximately $7.4 million. This well began producing in 2013 and had a 30-day average production rate of 795 Boe/d at 76% crude oil.

        North Park Basin—Jackson County, Colorado.    We control approximately 30,397 gross (24,605 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, 2012 were approximately 492 MBoe, 100% of which were crude oil. Our average net production during 2012 was approximately 114 Boe/d. None of our CO2 production is currently reflected in our reserve reports. During 2012, we re-entered and deepened one vertical well, classified as a non-proved location.

        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 not allocated any development or exploration capital to this area in 2013.

Mid-Continent Region

        In southern Arkansas, we target the oil-bearing Cotton Valley sands in the Dorcheat Macedonia and McKamie Patton Fields. As of December 31, 2012, our estimated proved reserves in this region were 20,558 MBoe, 68% of which were oil and natural gas liquids and 49% of which were proved developed. We currently operate 186 producing wells and, as of December 31, 2012, have an identified drilling inventory of approximately 122 gross (99.9 net) PUD drilling locations on our acreage. During 2012, we drilled 42 wells in the Dorcheat Macedonia and McKamie Patton Fields. We achieved an average production rate for 2012 of 4,689 Boe/d, of which 71% was from crude oil and liquids, and an average production rate for December 2012 of 5,285 Boe/d.

        Dorcheat Macedonia.    In the Dorcheat Macedonia Field, we average an 82% working interest and 68% net revenue interest on all producing wells, and all of our acreage is held by production. We have approximately 152 producing wells and our average net daily production during 2012 was approximately 4,289 Boe/d. During the month of December 2012, it was approximately 4,289 Boe/d. Our proved reserves in this Field are booked at 10-acre spacing and are approximately 18,948 MBoe. 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.

        Historically, the Dorcheat Macedonia Field reservoirs have responded favorably to fracture stimulation. Beginning in the fourth quarter of 2009, we began to implement pinpoint fracture stimulation utilizing coiled tubing. Post-fracture treatment tracer work has confirmed that pinpoint fracture placement provides much better coverage and penetration of the intended producing intervals.

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Results from wells employing this technique have seen initial production rates higher than historic rates and show stimulation of previously unstimulated zones.

        As of December 31, 2012, we have identified approximately 120 gross (97.9 net) PUD drilling locations on our acreage in this area. During 2012, we drilled 38 vertical Cotton Valley wells in Dorcheat-Macedonia. We have budgeted capital expenditures for 2013 of approximately $61.6 million for the development of this Field. In 2013, we expect to drill 30 PUD locations with a complete cost per well of approximately $1.8 million, approximately $1.7 million of which will be for initial drilling and completion. In addition, we plan to drill three wells testing our second 5-acre downspacing pilot. If successful, this program has the potential to significantly expand our drilling inventory in the Field.

        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, 2012, our estimated aggregate proved reserves in these Fields were approximately 1,610 MBoe, and average net daily production during 2012 was approximately 400 Boe/d. During 2012, we drilled 4 vertical Cotton Valley wells in the McKamie-Patton Field.

        Gas Processing Facilities.    Our gas processing facilities are located in Lafayette and Columbia counties in Arkansas and are strategically located to serve our production in the region. The facilities process natural gas and natural gas liquids, fractionate liquids into three components for sale, and sell three products at the facility's tailgate: propane, natural gasolines and natural gas. We also own approximately 150 miles of natural gas gathering pipeline that serve the facilities and surrounding Field areas and 32 miles of right-of-way crossing Lafayette County that can be utilized to connect the facility to other gas Fields or future sales outlets. Natural gas is sold at the tailgate of the facilities into CenterPoint pipeline connections. Processed natural gas liquids are held on site and trucked out. All gas entering the facility is processed in accordance with percent-of-proceeds contracts with upstream counterparties.

        In order to accommodate increased gas volumes and facilitate full Field development, we invested $16.2 million in 2012 to build another 12.5 MMcf/d processing facility at Dorcheat with associated 28,000 gallons per day of natural gas liquids capacity. This facility was completed in February 2013.

        In aggregate, our Arkansas gas processing facilities have approximately 40 MMcf/d of capacity with associated 86,000 gallons per day of natural gas liquids capacity. Our ownership of these facilities and 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. While we own the majority of the gas entering the facilities, we also process some third-party natural gas through the system. Neither the revenue nor volumes of this third-party natural gas is included in our reserve reports.

California

        During 2012, we owned acreage in four Fields in California: Kern River, Midway Sunset and Greeley, which we operated, and Sargent, which we did not. As of December 31, 2012, we had sold all of our interests in these Fields with the exception of Midway Sunset, which was in the process of being sold at year-end. Associated proved reserves as of December 31, 2012 for Midway Sunset were 31 MBoe.

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 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

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us to disclose in public reports. Our estimated proved reserves for the years ended December 31, 2012, 2011 and 2010 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.

        The table below summarizes our estimated proved reserves at December 31, 2012, 2011 and 2010 for each of the areas in which we operate. All of the reserve estimates at December 31, 2012, 2011 and 2010 presented in the table below are based on reports prepared by Cawley Gillespie & Associates, Inc., our independent reserve engineers. In preparing its reports, Cawley Gillespie & Associates, Inc. evaluated 100% of our properties at December 31, 2012, 2011 and 2010. 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.

Proved Reserves

Region/Field
  At
December 31,
2012
(MMBoe)
  At
December 31,
2011
(MMBoe)
  At
December 31,
2010
(MMBoe)
 

Mid-Continent

    20.6     21.6     22.9  

Dorcheat Macedonia

    19.0     19.9     20.8  

McKamie Patton

    1.6     1.6     2.0  

Other

    0.0     0.1     0.1  

Rocky Mountain

    32.4     21.4     9.1  

Wattenberg

    31.9     20.8     8.4  

North Park

    0.5     0.6     0.7  

California

    0.0     0.7     0.9  
               

Total

    53.0     43.7     32.9  
               

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        The following table sets forth more information regarding our estimated proved reserves at December 31, 2012, 2011 and 2010:

 
  At December 31,  
 
  2012   2011   2010  

Reserve Data(1):

                   

Estimated proved reserves:

                   

Oil (MMBbls)

    30.2     24.6     18.6  

Natural gas (Bcf)

    118.5     93.0     62.9  

Natural gas liquids (MMBbls)

    3.1     3.6     3.8  

Total estimated proved reserves (MMBoe)(2)

    53.0     43.7     32.9  

Percent oil and liquids

    63 %   65 %   68 %

Estimated proved developed reserves:

                   

Oil (MMBbls)

    14.3     10.6     7.4  

Natural gas (Bcf)

    48.9     31.3     20.1  

Natural gas liquids (MMBbls)

    1.3     1.2     0.7  

Total estimated proved developed reserves (MMBoe)(2)

    23.8     17.0     11.5  

Percent oil and liquids

    66 %   69 %   70 %

Estimated proved undeveloped reserves:

                   

Oil (MMBbls)

    15.8     14.0     11.2  

Natural gas (Bcf)

    69.6     61.7     42.8  

Natural gas liquids (MMBbls)

    1.8     2.4     3.0  

Total estimated proved undeveloped reserves (MMBoe)(2)

    29.2     26.7     21.3  

Percent oil and liquids

    60 %   61 %   67 %

(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 $94.71 per Bbl WTI and $2.757 per MMBtu HH, $96.19 per Bbl WTI and $4.12 per MMBtu HH, $79.43 per Bbl WTI and $4.38 per MMBtu HH for the years ended December 31, 2012, 2011 and 2010 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 locations on development spacing areas that are offsetting economic producers that are reasonably certain of economic production when drilled. Proved undeveloped reserves for other undrilled development spacing areas can be claimed only where it can be demonstrated with reasonable certainty that there is continuity of economic production from the existing productive formation. All proved undeveloped locations in our December 31, 2012 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, 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 12.8 MMBoe resulting from development in the Wattenberg Field in the Rocky Mountain region is comprised of 18.9 MMBoe of additions in extensions and discoveries offset by 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

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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 Henry Hub for the year ended December 31, 2011 to $94.71 per Bbl WTI and $2.757 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 is primarily due to extensions and discoveries associated with the Rocky Mountain region and is 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.

        The following table provides a reconciliation of PV-10 to the Standardized Measure at December 31, 2012, 2011 and 2010:

 
  December 31,  
 
  2012   2011   2010  
 
  (In millions)
 

PV-10

  $ 834.7   $ 794.0   $ 461.6  

Present value of future income taxes discounted at 10%

    (151.3 )   (127.8 )   (86.9 )
               

Standardized Measure

  $ 683.4   $ 666.2   $ 374.7  
               

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Proved Undeveloped Reserves

 
  Net Reserves, MBoe  
 
  At December 31,  
 
  2012   2011  

Previous Year End

    26,652     21,334  

Converted to Proved Developed Producing

    (5,166 )   (4,184 )

Additions from Capital Program

    13,913     10,190  

Acquisitions/Sales

    (430 )   0  

Revisions (pricing and engineering)

    (5,777 )   (688 )
           

Year End

    29,192     26,652  
           

        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 booking. 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 booking. At December 31, 2010, our proved undeveloped reserves were 21,334 MBoe. During 2011, 4,184 MBoe or 19.6% of our proved 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 work closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserves estimation process. Our Executive Vice President of Engineering and Planning, Gary A. Grove, is the technical person primarily responsible for overseeing the reserves process and insuring compliance with the Securities and Exchange Commission (SEC) definitions and guidance. Mr. Grove has over 30 years of industry experience with positions of increasing responsibility in engineering and evaluations and holds a Bachelor of Science degree in petroleum engineering.

        Throughout each fiscal year, the reserve committee of our board of directors and our technical team meet with representatives of our independent reserve engineering firm to review the reserves process and methodologies used in the estimation of the proved reserves. The reserve committee meets at least twice annually.

        Our technical team also 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.

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Independent Reserve Engineers

        The proved reserves estimate for the Company for the years ended December 31, 2010, 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 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. Natural gas prices have declined over the last three years as a result of a global economic downturn and increased supplies of natural gas.

        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, revenues and realized prices and production costs for the periods indicated. For additional information on price

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

 
  2012(1)   2011   2010  

Oil:

                   

Total Production (MBbls)

    2,191.0     887.3     415.8  

Wattenberg Field

    1,190.8     400.8     134.6  

Dorcheat Macedonia Field

    789.5     359.8     147.9  

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

    88.40   $ 85.51   $ 75.88  

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

    89.08   $ 89.67   $ 74.08  

Natural Gas:

                   

Total Production (MMcf)

    5,473.2     2,773.1     1,351.5  

Wattenberg Field

    2,485.6     1,072.2     391.6  

Dorcheat Macedonia Field

    2,973.8     1,642.2     828.6  

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

    3.76   $ 5.09   $ 4.99  

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

    3.62   $ 4.85   $ 4.76  

Natural Gas Liquids:

                   

Total Production (MBbls)

    284.7     183.8     129.8  

Wattenberg Field

             

Dorcheat Macedonia Field

    284.7     183.8     129.8  

Average sales price (per Bbl), including hedges

    55.54     67.23     56.23  

Average sales price (per Bbl), excluding hedges

    55.54     67.23     56.23  

Oil Equivalents:

                   

Total Production (MBoe)

    3,387.9     1,533.4     770.9  

Wattenberg Field

    1,605.0     579.5     199.8  

Dorcheat Macedonia Field

    1,569.8     817.3     416.3  

Average daily production (Boe/d)

    9,257     4,201.1     2,112.1  

Wattenberg Field

    4,385.4     1,587.7     547.4  

Dorcheat Macedonia Field

    4,289.1     2,239.2     1,140.5  

Average Production Costs (per Boe)

    9.06     13.37     16.04  

(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, 2012.

(2)
Excludes ad valorem and severance taxes.

Principal Customers

        Two of our customers, Plains Marketing and Lion Oil, comprised 34% and 29%, respectively, of our total revenue for the year ended December 31, 2012. No other single non-affiliated purchaser accounted for 10% or more of crude oil and natural gas sales in 2012. We believe the loss of any one purchaser would not have a material effect on our financial position or results of operations, since there are numerous potential purchasers 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 oil and natural gas wells in which we owned a working interest at December 31, 2012.

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

Rocky Mountain

    266     246.4             266     246.4     254     243.6  

Mid-Continent

    186     157.6             186     157.6     180     157.3  

California

    21     21             21     21     21     21  

Total

    473     425             473     425     455     421.9  

(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, 2012 for each of the areas where we operate. 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  

Rocky Mountain

    37,086     34,837     27,317     20,453     64,403     55,290  

Mid-Continent

    14,840     13,367             14,840     13,367  

California

    480     480     120     47     600     527  
                           

Total

    52,406     48,684     27,437     20,500     79,843     69,184  
                           

Undeveloped acreage

        The following table sets forth the number of gross and net undeveloped acres as of December 31, 2012 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
2013
  Expiring
2014
  Expiring
2015
 
 
  Gross   Net   Gross   Net   Gross   Net  

Rocky Mountain

    1,017     724     481     52     3,481     3,104  

Mid-Continent

                         

California

    120     47                  
                           

Total

    1,137     771     481     52     3,481     3,104  
                           

        In 2012, federal and state leases covering 160 acres in our Rocky Mountain region expired, all of which were in the Wattenberg Field.

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Drilling Activity

Exploratory

        The following table describes the exploratory wells we drilled during the years ended December 31, 2012, 2011 and 2010.

 
  Productive
Wells
  Dry Wells   Total  
Year
  Gross   Net   Gross   Net   Gross   Net  

2012

            1     1     1     1  

2011

    53     52.9             53     52.9  

2010

    14     14.0             14     14.0  

Development

        The following table describes the development wells we drilled during the years ended December 31, 2012, 2011 and 2010.

 
  Productive
Wells
  Dry Wells   Total  
Year
  Gross   Net   Gross   Net   Gross   Net  

2012

    149     140.9             149     140.9  

2011

    53     48.9             53     48.9  

2010(1)

    26     25.9             26     25.9  

(1)
We contract operated for HEC from May 2009 until we acquired the properties in December 2010. Excluded from the development activity are 15 gross (11.3 net) wells drilled as contract operator for HEC during year 2010, in which we had a minority working interest.

Present Activity

        The following table describes drilling activities as of December 31, 2012.

 
  Development
Wells
  Exploratory
Wells
  Total  
 
  Gross   Net   Gross   Net   Gross   Net  

Rocky Mountain

    1     1.0             1     1.0  

Mid-Continent

    3     3.0             3     3.0  

California

                         

Total

    4     4.0             4     4.0  

Capital Expenditure Budget

        Our anticipated 2013 capital budget is approximately $394 million which represents an increase of 16% over capital spending during 2012 of $341 million. We plan to spend approximately $324 million or 82% of our total 2013 budget in the Wattenberg Field with the remaining $70 million allocated to our assets in southern Arkansas. In total, we plan to spend $342 million on operated drilling and completion activities with the remainder allocated to non-operated drilling and completion activities, costs associated with our gas plant expansion in Arkansas, seismic and maintenance operations.

        While we have budgeted approximately $394 million for these purposes, the ultimate amount of capital we will expend may fluctuate materially based on, among other things, market conditions, the

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success of our drilling results as the year progresses and changes in the borrowing base under our credit facility.

Hedging 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 transactions.

        As of December 31, 2012, we had the following economic hedges in place, which settle monthly:

Oil Contracts

Settlement Period
  Derivative
Instrument
  Total Notional
Amount
(BBL/Mmbtu)
  Average
Floor
Price
  Average
Ceiling
Price
  Fair Market
Value of Asset
(Liability)
 

Oil

                             

2013

  Collar     890,616     88.92     103.00     1,727,192  

  Swap     1,035,417     88.54           (4,864,853 )

2014

  Collar     672,000     85.00     95.50     (1,235,168 )

  Swap     228,000     90.80           (308,287 )

Gas

                             

2013

  Swap     154,806     6.40           450,872  

        We do not apply hedge accounting treatment to any commodity derivative contracts. Settlements on these contracts will not impact our realized commodity prices during the periods they cover. Instead, any settlements on these contracts are shown as a component of other income and expenses as a realized (gain) loss on derivative instruments. See Note 12 to our consolidated financial statements for additional information regarding our derivative instruments.

Title to Properties

        Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business. We believe that we have generally satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make minimal investigation of title at the time we acquire undeveloped properties. Generally, we make title investigations and receive title opinions of local counsel only before we commence drilling operations, subject to the availability and examination of accurate title records, except in Arkansas and certain cases in the Rocky Mountain region where we have commenced drilling without complete legal examination of title, but are in the process of obtaining title opinions. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with the operation of our business.

Bonanza Creek Acquisition History

        Acquiring properties that are complementary to our existing positions or that have significant undeveloped resource potential has been an important part of our growth strategy. The following

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describes some of the acquisitions completed by our predecessor to build our current position in the Mid-Continent and the Rocky Mountain regions:

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, 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 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.

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

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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.

        The regulatory burden on the industry increases the cost of doing business and affects profitability. Failure to comply with applicable laws and regulations can result in substantial penalties and threaten loss of the authorization to operate. Furthermore, such laws and regulations are frequently amended or reinterpreted, and new proposals that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission ("FERC") and the courts. We believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.

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

        Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by FERC pursuant to the Interstate Commerce Act ("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.

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

        Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated by FERC under the Natural Gas Act of 1938 ("NGA"), the Natural Gas Policy Act of 1978 ("NGPA"), and regulations issued under those statutes. 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 market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the NGPA and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

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        FERC regulates interstate natural gas transportation rates, and terms and conditions of service, which affect the marketing of natural gas that we produce and the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open access and non-discriminatory basis.

        Natural gas gathering services located upstream of jurisdictional transmission services and those located onshore and in state waters are subject to state regulation. Although FERC has set forth a general test for determining whether facilities perform a nonjurisdictional gathering function or a jurisdictional transmission function, FERC's determinations as to the classification of facilities are done on a case by case basis. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Such regulation has not generally included regulation of the rates, terms and conditions of gathering services, although natural gas gathering may receive greater regulatory scrutiny in the future.

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

        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.

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

        In 2007, FERC took steps to enhance its market oversight and monitoring of the natural gas industry by issuing several rulemaking orders designed to promote gas price transparency and to prevent market manipulation. In December 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements ("Order No. 704"). Pursuant to Order No. 704, wholesale buyers and sellers of annual quantities of 2.2 million MMBtu or more of natural gas in the previous calendar year, including intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, by May 1 of each year, aggregate volumes

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of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC's policy statement on price reporting. Some of our operations may be required to comply with Order No. 704's annual reporting requirements.

        On November 15, 2012, the Commission issued a Notice of Inquiry seeking comments on what additional changes, if any, should be made to its regulations under the natural gas market transparency provisions of section 23 of the NGA, as adopted in the Energy Policy Act of 2005. In particular, the Commission is considering proposing to require all market participants engaged in sales of wholesale physical natural gas in interstate commerce to report quarterly to the Commission every natural gas transaction within the Commission's NGA jurisdiction that entails physical delivery for the next day (i.e., next day gas) or for the next month (i.e., next month gas).

        In October 2010, FERC issued a Notice of Inquiry seeking public comment on the issue of whether and how parties that hold firm capacity on some intrastate pipelines can allow others to use their capacity, including to what extent buy/sell transactions should be permitted and whether FERC should consider requiring such pipelines to offer capacity release programs. In the Notice of Inquiry, FERC granted a blanket waiver regarding such transactions while FERC is considering these policy issues. The comment period has ended, but FERC has not yet issued an order.

        With regard to our physical sales of natural gas, we are required to observe anti-market manipulation laws and related regulations enforced by FERC. With regard to our sales of petroleum and petroleum products, we are required to observe anti-market manipulations laws and related regulations enforced by the Federal Trade Commission ("FTC"). In addition, the CFTC has enforcement authority over market manipulation with respect to certain derivative contracts.

        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 requires 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.

Environmental, Health and Safety Regulation

        Our exploration, development, production and processing operations are subject to various federal, state and local laws and regulations relating to health and safety, the discharge of materials and environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by protected plant and animal species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and

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abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

        These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. Environmental, health and safety laws and regulations increase the cost of doing business in the oil and gas industry and consequently affect profitability. Additionally, the Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly permitting and compliance, waste handling and disposal, cleanup or remediation requirements for the oil and gas industry could have a significant impact on our operating costs.

        The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in more stringent and costly requirements could have a material adverse effect on our operations and financial position in the future. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons. We maintain insurance against costs of cleanup operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that this will continue in the future.

        The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance in the future 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. CERCLA also authorizes EPA and, in some instances, third parties to act in response to hazardous substance threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Further, it is not uncommon for neighboring landowners and other third parties to file other claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment. Although CERCLA's petroleum exclusion provision excludes "crude oil or any fraction thereof" from its definition of hazardous substance, we do generate materials in the course of our operations that may contain CERCLA hazardous substances.

        We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. RCRA imposes requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be

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regulated as hazardous wastes, or simply as solid waste. RCRA regulations specifically exclude from the definition of hazardous waste "drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy." However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs and the natural gas and oil industry in general.

        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 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. In December 2011, both Houses of the U.S. Congress passed bipartisan legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules. 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 is considering two 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.

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        Since August 2006, the U.S. Environmental Protection Agency ("EPA") has published several new regulations under the CAA to control emissions from stationary internal combustion engines. Over time, those rules may require us to undertake certain expenditures and activities, likely including paying higher prices for new engines; installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on a portion of our existing engines located at major sources of hazardous air pollutants, and all our existing engines over a certain size regardless of location; following prescribed maintenance practices for engines; and implementing additional emissions testing, monitoring and recordkeeping.

        On August 16, 2012, EPA published final rules that established new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA's rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds ("VOCs"), a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities, and reduced emission completion requirements for hydraulically fractured gas wells. The rules also established specific new requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules contain more stringent leak detection requirements for natural gas processing plants. 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. EPA intends to issue revised rules in 2013 that are likely responsive to some of these requests. The final revised rules could require modifications to our operations or increase our capital and operating costs without being offset by increased product capture. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements with any certainty.

        The United States is a party to the United Nations Framework Convention on Climate Change, an international treaty focused on stabilizing greenhouse gas ("GHG") concentrations in the atmosphere at a level that would prevent serious damage to the Earth's climate. While neither the treaty itself, nor subsequent related conferences, have established an obligation for the U.S. to reduce its GHG emissions by a set amount, it has put significant political pressure on the U.S. to take responsive action. Both houses of Congress have previously considered legislation to reduce emissions of GHG. Any future federal laws, treaties or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

        EPA has begun to regulate GHG emissions. In December 2009, EPA published its finding that certain emissions of GHG presented an endangerment to human health and the environment. These findings by EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHG under existing provisions of the CAA. Consequently, EPA required a reduction in emissions of GHG from new motor vehicles for the 2012 model year and subsequent years. Furthermore, EPA published a final rule on June 3, 2010 to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs. This rule "tailors" these permitting programs to apply to certain major stationary sources of GHG emissions, such as power plants and oil refineries, in a multi-step process, with the largest-emitting sources first subject to permitting. Facilities required to obtain Prevention of Significant Deterioration ("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. Starting in January 2011, stationary sources that are already obtaining a PSD or Title V major source permit for other pollutants must include GHG in their permits if they emit at least 75,000 tons of these emissions per year. In July 2012, the rule expanded to include all new facilities that emit at least 100,000 tons of GHG per year.

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        In addition, in October 2009, EPA issued a final rule requiring the reporting of GHG from specified large GHG emission sources beginning in 2011 for emissions in 2010. Our McKamie processing facility in Arkansas is required to report under this rule. On November 30, 2010, EPA published a final rule expanding the existing GHG monitoring and reporting rule to include certain large onshore and offshore oil and gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities is required on an annual basis and began in 2012 for emissions occurring in 2011. Our McKamie processing facility and our North Park Basin, Colorado, facility are required to report under this rule. EPA also published a final rule requiring reporting for natural gas liquid fractionators, which applies to the McKamie processing facility and a separate reporting rule for suppliers of carbon dioxide, which affects our operations in the North Park Basin. Several of EPA's GHG rules are being challenged in court proceedings, and depending on the outcome of such proceedings, such rules may be modified or rescinded or EPA could develop new rules. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHG from, our equipment and operations could require us to incur costs to reduce emissions of GHG associated with our operations or could adversely affect demand for the oil and natural gas we produce.

        Almost one-half of the states have begun taking actions to control and/or reduce emissions of GHG, primarily through the planned development of GHG emission inventories and/or GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.

        Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. We cannot predict with any certainty at this time how these possibilities may affect our 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, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for oil or natural gas we produce, or otherwise cause us to incur significant costs in preparing for or responding to those effects.

        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. Pursuant to the CWA and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Surface spills and leaks are controlled, contained and remediated in accordance with the applicable requirements of state oil and gas commissions, as well as any Spill

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Prevention, Control and Countermeasures ("SPCC") plans we maintain in accordance with EPA requirements. This would include any action up to and including total abandonment of the wellbore.

        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.

        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, 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.    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. The State of Colorado recently adopted regulations regarding hydraulic fracturing, which went into effect April 1, 2012. These regulations require disclosure of all chemicals used in hydraulic fracturing fluid, subject to certain measures to protect proprietary information. The regulations allow disclosure through the FracFocus web site, which is operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council. 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.

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        Federal agencies are also considering additional regulation of hydraulic fracturing. EPA recently asserted regulatory authority over hydraulic fracturing involving diesel additives under the SDWA's Underground Injection Control Program and is developing guidance for how permitting authorities should handle such activities. 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 study into the effects of hydraulic fracturing on drinking water. 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. The United States Department of the Interior has also announced its intention to propose a new rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water.

        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.

        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 300 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 been used more universally since the early 1990s. We and our predecessor companies have completed over 60 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.

        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

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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.

        The National Environmental Policy Act of 1969 ("NEPA"), requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment before their commencement. Generally, federal agencies must prepare either an environmental assessment or an environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the environment. The NEPA process involves public input through comments, which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the administrative and federal court systems by process participants. Although we believe that our actions do not typically trigger NEPA analysis, should we ever be subject to NEPA review, the process may result in delaying the permitting and development of projects, increase the costs of permitting and developing some facilities and could result in certain instances in the cancellation of certain leases.

        Our properties located in Colorado are subject to the authority of the Colorado Oil and Gas Conservation Commission ("COGCC"). 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. 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.

Employees

        As of December 31, 2012, we employed 155 people. 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. We also utilize the services of independent contractors to perform various Field and other services.

Offices

        As of December 31, 2012, we leased 42,712 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 15,182 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.

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        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.

Risks related to the oil and natural gas industry and 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 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. 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

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natural gas reserves" below. 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 63% of our estimated proved reserves as of December 31, 2012 were oil and natural gas liquids reserves, our financial results are more sensitive to movements in oil prices. The price of oil has been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2012, the daily NYMEX WTI oil spot price ranged from a high of $109.77 per Bbl to a low of 77.69 per Bbl, and the NYMEX natural gas Henry Hub spot price ranged from a high of $3.90 per MMBtu to a low of $1.91 per MMBtu.

        As of December 31, 2012, we had commodity price hedging agreements for 2013 on approximately 1.9 MMBbls of oil with an average minimum price of $88.72/Bbl and 154.8 MMcf of natural gas with an average minimum price of $6.40/Mcf. Additionally, we had 0.9 MMBbls of oil hedged in 2014 with an average minimum price of $90.30/Bbl.

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:

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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 "Item 1. Business—Estimated Proved Reserves" for information about our estimated oil and natural gas reserves and the PV-10 (a non-GAAP financial measure) as of December 31, 2012, 2011 and 2010.

        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. 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.

        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, oil Field 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.

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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, 2012, 2011 and 2010, 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:

        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 prices decline by $10.00/Bbl, then our PV-10 as of December 31, 2012 would decrease by approximately $161.6 million. PV-10 is a non-GAAP financial measure (refer to Item 1—Business—Estimated Proved Reserves 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 oil shale, 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.

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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 were $304.6 million and $158.9 million (including $13.9 million and $1.8 million for the acquisition of oil and gas properties) related to capital and exploration expenditures for the years ended December 31, 2012 and 2011, respectively. Our capital expenditure budget for 2013 is approximately $394 million, with approximately $342 million allocated for drilling and completion operations. 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.

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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.

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.

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 93% of our current production, each of our development projects and most of our exploration potential. During 2012, we initiated a non-core divestiture program to focus our portfolio and sold certain non-core assets in California. As a result of these portfolio changes, our operations and production are more concentrated.

        The Wattenberg and Dorcheat Macedonia Fields represent 47% and 46%, respectively, of our 2012 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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Market conditions or operational impediments, like lack of available transportation, may hinder our production or adversely impact our ability to receive market prices for our production or to achieve expected drilling results.

        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 availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. 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. 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 other disruptions of service. Curtailments and disruptions may last from a few days to several months, and we have no control over when or if third-party facilities are restored. Recently, the gas gathering systems serving the Wattenberg Field have 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 shale. 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 55% of our total proved reserves were classified as proved undeveloped as of December 31, 2012. 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 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.

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        According to estimates included in our December 31, 2012 proved reserve report, if, on January 1, 2013, 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 8.9% over 10 years, including 54.2% during the first year. If we fail to replace reserves through drilling, our level of production and cash flows will be affected adversely. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both.

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.

        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:

        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 are susceptible to damage from natural disasters such as flooding 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

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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 interpretation. 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.

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, 2012, only 329 gross (244.5

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net) of our approximately 1,600 identified potential future gross drilling locations were 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 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 certain of our oil and gas leases stipulate that the lease will terminate if not held by production. As of December 31, 2012, all of our acreage in Arkansas was held by production and not subject to lease expiration. As of December 31, 2012, 10,127 net acres of our properties in the Rocky Mountain region, specifically 7,497 acres in the Wattenberg Field and 2,630 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 three years, then 724 net acres will expire in 2013, 52 net acres will expire in 2014 and 3,104 net acres will expire in 2015. If our leases expire, we will lose our right to develop the related properties.

We may incur losses as a result of title deficiencies.

        We purchase working and revenue interests in oil and natural gas leasehold interests from third parties or directly from the mineral fee owners. The existence of a title deficiency can reduce or destroy the value of a lease and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available. We forego the expense of retaining lawyers to examine the title to the mineral interest to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled, except in Arkansas and certain cases in the Rocky Mountain region where we have commenced drilling without complete legal examination of title, but are in the process of obtaining title opinions. As is customary in our industry, we rely upon the judgment of oil and natural gas lease brokers, in-house landmen or independent landmen who perform the Field work in examining records in the appropriate governmental offices and abstract facilities before attempting to acquire or place under lease a specific mineral interest. We do not always perform curative work to correct deficiencies in the marketability of the title to us. In cases involving more serious title problems, the amount paid for affected oil and natural gas leases can be lost, and the target area can become undrillable. We may be subject to litigation from time to time as a result of title issues.

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 on shale drilling in the United States, even in jurisdictions that are

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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 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 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

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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. Recently, the Environmental Protection Agency 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. 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. After several parties challenged the new air regulations in court, the EPA announced that it intends to grant requests for reconsideration of certain requirements and to evaluate 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 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 restrict its use. For example, the EPA has commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. 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. Legislation has also been introduced in the United States Congress that would amend the federal Safe Drinking Water Act ("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 permits for fracturing, 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. At this time, it is not clear what action, if any, the United States Congress will take on hydraulic fracturing. Beyond that, the U.S. Department of the Interior proposed a new rule regulating hydraulic fracturing activities on federal lands that would have covered disclosure, well bore integrity, and handling of flowback water, but now intends to issue a revised proposal.

        In addition to these ongoing federal initiatives, state and local governments where we operate have moved to require disclosure of fracturing fluid components or otherwise regulate their use more closely. In certain areas of the country, new drilling permits for hydraulic fracturing have been put on hold pending development of additional standards. Similarly, governmental authorities continue to develop requirements for the emission of greenhouse gases that are being linked to climate change.

        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

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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.

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, 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 EPA, contributing to the warming of the Earth's atmosphere and other climatic changes. Consistent with its findings, EPA has proposed or adopted various regulations under the Clean Air Act to address GHG. Among other things, EPA is limiting emissions of GHG from new cars and light duty trucks beginning with the 2012 model year. In addition, 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. 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, and which may form the basis for further GHG regulation. Many of EPA's GHG rules are subject to legal challenges, but have not been stayed pending judicial review. Depending on the outcome of such proceedings, such rules may be modified or rescinded or EPA could develop new rules. 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, 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 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

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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 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.

The loss of senior management or technical personnel 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 or technical personnel, including Michael R. Starzer, our President and Chief Executive Officer, 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.

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We recorded substantial compensation expense in 2012, and we are likely to incur substantial additional compensation expense related to our future grants of stock compensation, which may have a material negative impact on our operating results for the foreseeable future.

        We incurred compensation expense in 2012 in the amount of $4.5 million compared to $4.4 million in 2011. 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 and other risks associated with our business.

        The Dodd-Frank Act, which was signed into law on July 21, 2010, contains significant derivatives regulation. The Dodd-Frank Act and any new regulations promulgated under the act 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. We may need to expend significant resources complying with and adapting to the new regulatory regime, including significant reporting and record keeping requirements, as well as otherwise ensuring that we are able to rely on certain exemptions from mandatory clearing requirements. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. 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

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prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

We may not be able to generate enough cash flow to meet our debt obligations.

        We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt obligations. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

        If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which would in turn trigger cross-acceleration or cross-default rights between relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings. If amounts outstanding under our revolving credit facility were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders. Please see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and capital resources."

Our revolving credit facility contains operating and financial restrictions that may restrict our business and financing activities.

        Our revolving credit facility contains a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

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        As a result of these covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.

Our level of indebtedness may increase and reduce our financial flexibility.

        As of December 31, 2012, we had $158 million of indebtedness outstanding under our revolving credit facility, and $119 million available for future secured borrowings under this facility. 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:

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

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 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.

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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 $38.6 million in receivables at December 31, 2012.

        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, 2012, sales to Lion Oil Trading & Transport and Plains Marketing accounted for approximately 29% and 34%, 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 the Company's 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 NYSE, among other laws, rules, regulations and requirements. Complying with these laws, rules, regulations and requirements occupies 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

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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.

        The U.S. President's Fiscal Year 2013 Budget Proposal includes provisions 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. The passage of any legislation as a result of the budget proposal or any other similar change 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.

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. Consequently, our stockholders' only opportunity to achieve a return on their

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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 prospectus and contained in our reports filed with the SEC, 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. Project Black Bear LP ("Black Bear") and Her Majesty the Queen in Right of Alberta, in her own capacity and as trustee/nominee for certain Alberta pension clients ("HMQ"), own 8,166,134 shares, or approximately 20.34% of our total outstanding shares. These stockholders are parties to a registration rights agreement with us. Pursuant to this agreement, we have agreed to effect the registration of shares held by Black Bear and HMQ if they so request 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.

We may issue debt and equity securities or securities convertible into equity securities, any of which may be senior to our common stock as to distributions and liquidation.

        We have filed a shelf registration statement that gives us the ability to issue a number of different securities. In the future, we may issue debt or equity securities or securities convertible into or exchangeable for equity securities, or we may enter into debt-like financing that is unsecured or secured by any or all of our properties. Such securities may be senior to our common stock as to distributions. In addition, in the event of our liquidation, our lenders and holders of our debt and preferred securities would receive distributions of our available assets before distributions to the holders of our common stock.

Our certificate of incorporation and bylaws contain, and Delaware law contains, provisions that may prevent, discourage or frustrate attempts to replace or remove our current management by our stockholders, even if such replacement or removal may be in our stockholders' best interests.

        Our certificate of incorporation and bylaws contain, and Delaware law contains, provisions that could enable our management to resist a takeover attempt. Among other things, our certificate of incorporation and bylaws:

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        These provisions could:

West Face Capital Inc. and Alberta Investment Management Corporation together 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.

        West Face Capital, Inc. ("West Face"), as advisor to Black Bear, and Alberta Investment Management Corporation, a Canadian corporation and investment manager to HMQ and certain Alberta pension funds ("AIMCo"), together may be deemed to beneficially own, control or have substantial influence over approximately 20.34% of our outstanding common stock. West Face Capital and AIMCo, on behalf of HMQ and certain Alberta pension funds, have entered into an investment

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management agreement pursuant to which West Face Capital has the right to vote the shares of our common stock held by HMQ. West Face Capital also has the right, pursuant to an advisory agreement with Black Bear, to vote the shares held by Black Bear. Accordingly, West Face Capital 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, West Face Capital and AIMCo, on behalf of its clients, voting together as a group would have the ability to exert significant influence over the company.

        A concentration of ownership in West Face Capital alone or together with 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 Black Bear and 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 incorporated herein by reference.

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 we are aware of.

        In June 2011, Frank H. Bennett, a co-manager of Bonanza Creek Oil Company, LLC ("BCOC"), Bonanza Creek Energy, LLC's ("BCEC") predecessor, and former chairman of BCEC, made a demand against Michael R. Starzer, our President and Chief Executive Officer, focusing on Mr. Starzer's handling of the operation, accounting and finances of BCOC and BCEC primarily during the 2005-2006 time period. Mr. Bennett's demands do not allege any wrongdoing by or claims against Bonanza Creek Energy, Inc. This matter was sent to arbitration in July 2011. An arbitration hearing commenced in July

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2012 and concluded in October 2012. At the end of November 2012, the arbitration panel issued an order finding in favor of Mr. Starzer on all of the plaintiff's claims. This order is final and non-appealable, thus effectively and favorably terminating the claims asserted by Mr. Bennett. During the period from January 1, 2012 through December 31, 2012, the Company incurred approximately $3,000,000 for legal fees and other expenses related to Mr. Bennett's claims.

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 New York Stock Exchange ("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 since our initial public offering.

 
  High   Low  

4th Quarter 2011 (from December 15, 2011)

  $ 15.50   $ 12.39  

1st Quarter 2012

    22.25     12.62  

2nd Quarter 2012

    22.66     14.52  

3rd Quarter 2012

    24.40     15.00  

4th Quarter 2012

    29.03     20.83  

1st Quarter 2013 (through February 28, 2013)

    35.25     29.23  

        Holders.    As of February 28, 2013, there were approximately 87 registered holders of our common stock.

        Dividends.    We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility 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 28, 2013, the last sale price of our common stock, as reported on the NYSE, was $33.83 per share.

        Issuer Purchases of Equity Securities.    The following table contains information about our acquisition of equity securities during the three months ended December 31, 2012:

Period
  Total
Number of
Shares
Exchanged(1)
  Average Price
Paid per
Share
  Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
  Maximum Number (or
Approximate Dollar Value) of
Shares that May Be Purchased
Under the Plans or Programs
 

Oct 1—Oct 31, 2012

      $          

Nov 1—Nov 30, 2012

    3,108     22.81          

Dec 1—Dec 31, 2012

    14,578     26.17          

Total

    17,686   $ 25.58          

(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

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Item 6.    Selected Financial Data.

        The following tables set forth selected historical financial data of the Company and our predecessor, BCEC, as of and for the period indicated. Selected historical financial data of the Company and BCEC for all periods prior to December 31, 2011, have been recast to present the results of operations and financial position of the Company related to certain properties in California sold in 2012 or held for sale as of December 31, 2012, as discontinued operations. See the Company's Current Report on Form 8-K filed on January 28, 2013. See also "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 of Part II of this Annual Report on Form 10-K and Note 4 to the consolidated financial statements in Item 8 of Part II of this Annual Report on Form 10-K.

        In management's opinion, the financial statements include all adjustments necessary for the fair presentation of our financial condition as of such date and our results of operations for such periods.

        The selected historical financial data should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and both our and our predecessor's

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financial statements and the notes to those financial statements included in Item 8 of Part II of this Annual Report on Form 10-K.

 
  Bonanza Creek Energy
Company LLC
("Predecessor")
  Bonanza Creek Energy, Inc.  
 
  2008   2009   Period
Ended
December 23,
2010(1)
  Period from
Inception
(December 23,
2010) to
December 31,
2010
  Year Ended
December 31,
2011
  Year Ended
December 31,
2012
  Pro Forma
2010(2)
 
 
   
  (in thousands, except per share amounts)
  (unaudited)
 

Statement of Operations Data:

                                           

Revenues:

                                           

Oil sales

  $ 27,171   $ 22,377   $ 29,608   $ 1,200   $ 79,568   $ 195,175   $ 40,466  

Natural gas sales

    5,160     3,655     6,226     207     13,442     19,795     10,253  

Natural gas liquids and CO2 sales

    2,782     3,169     7,672     213     12,714     16,235     8,365  
                               

Total revenues

    35,113     29,201     43,506     1,620     105,724     231,205     59,084  
                               

Operating expenses:

                                           

Lease operating

    8,633     10,745     11,948     419     18,253     30,695     14,377  

Severance and ad valorem taxes

    1,439     1,984     1,468     66     5,918     13,674     2,368  

Depreciation, depletion and amortization

    11,065     12,594     12,598     436     28,014     66,202     18,856  

General and administrative

    7,477     7,610     8,375     324     13,164     26,922     9,339  

Employee stock compensation(3)

                    4,449     4,483      

Exploration

    9         226         878     10,715     246  

Impairment of oil and gas properties(4)

    1,594                 623     611      

Cancelled private placement(5)

            2,378                 2,378  
                               

Total operating expenses

    30,217     32,933     36,993     1,245     71,299     153,302     47,564  
                               

Income (loss) from operations

    4,896     (3,732 )   6,513     375     34,425     77,903     11,520  

Other income (expense):

                                           

Interest expense

    (12,227 )   (16,582 )   (18,001 )   (58 )   (4,017 )   (4,133 )   (1,263 )

Amortization of debt discount

    (5,987 )   (7,963 )   (8,862 )                

Write off of deferred financing costs

            (1,663 )               (1,663 )

Gain on sale of oil and gas properties

    8                          

Unrealized gain (loss) in fair value of warrant put option(6)

    70,972     (80,640 )   34,345                  

Unrealized gain (loss) in fair value of commodity derivatives

    48,716     (34,589 )   (7,605 )   (514 )   225     1,650     (8,119 )

Realized gain (loss) on settled commodity derivatives

    1,913     13,451     5,919     (47 )   (3,024 )   (725 )   5,872  

Other income (loss)

    (229 )   (180 )   19         (110 )   (133 )   (46 )
                               

Total other income (expense)

    103,166     (126,503 )   4,152     (619 )   (6,926 )   (3,341 )   (5,219 )
                               

Income (loss) from continuing operations before taxes

    108,062     (130,235 )   10,665     (244 )   27,499     74,562     6,301  

Income tax benefit (expense)(7)

                90     (12,890 )   (29,991 )   (2,319 )
                               

Income (loss) from continuing operations

    108,062     (130,235 )   10,665     (154 )   14,609     44,571     3,982  
                               

Discontinued operations(8)

                                           

(Loss) income from operations associated with oil and gas properties held for sale (including impairments in 2008, 2009, 2011, and 2012 of $24.8 million, $0.6 million, $3.4 million, and $1.6 million respectively)(4)

    (39,308 )   149     64     (13 )   (3,610 )   (927 )   (312 )

Gain on sale of oil and gas properties

        303     4,055             4,192     4,055  

Income tax (expense) benefit

                5     1,692     (1,313 )   (1,377 )
                               

(Loss) income from discontinued operations

    (39,308 )   452     4,119     (8 )   (1,918 )   1,952     2,366  
                               

Net income (loss)

  $ 68,754   $ (129,783 ) $ 14,784   $ (162 ) $ 12,691   $ 46,523   $ 6,348  
                               

Basic and Diluted Income Per Share(9)

                                           

Income from continuing operations

                    $   $ 0.49   $ 1.12   $ 0.14  
                                     

Income from discontinued operations

                    $   $ (0.6 ) $ 0.05   $ 0.08  
                                     

Net income per common share

                    $   $ 0.43   $ 1.17   $ 0.22  
                                     

Weight Average Shares Outstanding, Basic and Diluted

                      29,123     29,576     39,788     29,123  
                                     

(1)
We completed our Corporate Restructuring on December 23, 2010.

(2)
The pro forma information above gives effect to our Corporate Restructuring as if it had occurred on January 1, 2010. See "—Unaudited Pro Forma Financial Data."

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(3)
In connection with our IPO, the Company distributed 243,945 fully vested shares of common stock previously held in trust to our employees and recorded a $4.1 million stock compensation charge. In addition, the Company distributed the remaining 3,400 shares of our former Class B common stock to our employees. In connection with our IPO, all issued and outstanding shares of our former Class B Common Stock converted into 437,787 shares of restricted common stock, vesting over a three year period and we recorded a $0.1 million stock compensation charge. In connection with our LTIP, the company granted 736,780 shares of restricted common stock during 2012, vesting over a three year period. We expect to recognize employee stock compensation expense relating to these grants during the years ended December 31, 2013, 2014, and 2015 of approximately $6.5 million, $6.3 million, and $1.1 million, respectively.

(4)
The impairment for the year ended 2008 resulted from a write-down of the carrying value of our oil and natural gas reserves due to depressed year-end natural gas prices. 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.

(5)
Expenditures in connection with a cancelled private placement of our preferred stock.

(6)
In connection with its purchase of our senior subordinated notes D.E. Shaw Synoptic Portfolios 5, L.L.C. received warrants to purchase equity interests in our predecessor. These warrants contained a put right exercisable beginning on May 17, 2014. The periods presented for our predecessor reflect the changes in the fair market value of that put option. The warrants and aggregate warrant exercise price were exchanged for shares of our common stock in connection with our Corporate Restructuring.

(7)
Our predecessor, BCEC, was a partnership for federal income tax purposes and, therefore, was not subject to entity-level taxation. Our pro forma results reflect our taxation as a subchapter "C" corporation at an estimated combined state and federal income tax rate of 36.8%.

(8)
The results of operation and impairment loss related to non-core properties interests in California sold in 2012 or held for sale have been reflected as discontinued operations. See Note 4 to our consolidated financial statements included in Item 8 of Part II of this Annual Report on Form 10-K.

(9)
As a limited liability company, ownership interests in our predecessor were held as units rather than shares.

 
  Bonanza Creek Energy
Company, LLC
(Predecessor)
  Bonanza Creek
Energy, Inc.
 
 
  As of December 31,   As of December 31,  
 
  2008   2009   2010   2011   2012  
 
  (in thousands)
 

Balance Sheet Data:

                               

Cash and cash equivalents

  $ 4,088   $ 2,522   $   $ 2,090   $ 4,268  

Property and equipment, net

    182,976     177,126     481,374     618,229     943,175  

Oil and gas properties held for sale, less accumulated depreciation and depletion

    12,304     11,241     15,208     9,896     582  

Total assets

    241,625     211,552     516,104     664,349     1,002,490  

Long term debt, including current portion:

                               

Credit facility

    107,000     99,000     55,400     6,600     158,000  

Senior subordinated notes, net of discount

    75,499     92,442              

Subordinated unsecured note

    10,000     10,799              

Warrant put options(1)

    828     81,468              

Total members'/stockholders' equity (deficit)

    35,988     (93,795 )   356,380     527,982     578,518  

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  Bonanza Creek Energy
Company, LLC
(Predecessor)
  Bonanza Creek Energy, Inc.  
 
  Year Ended
December 31,
   
  Inception
(December 23,
2010) to
December 31,
2010(2)
   
   
 
 
  Period
Ended
December 23,
2010
  Year
Ended
December 31,
2011
  Year
Ended
December 31,
2012
 
 
  2008   2009  
 
  (in thousands)
 

Other Financial Data:

                                     

Net cash provided by (used in) operating activities

  $ 11,128   $ 11,134   $ 22,759   $ (1,633 ) $ 57,603   $ 156,910  

Net cash provided by (used in) investing activities

    (79,581 )   (7,185 )   (32,127 )   (817 )   (158,902 )   (304,551 )

Net cash provided by (used in) financing activities

    72,541     (5,515 )   9,297         103,389     149,819  

(1)
The warrants and aggregate warrant exercise price were exchanged for shares of our common stock in connection with our Corporate Restructuring.

(2)
We completed our Corporate Restructuring on December 23, 2010.


Unaudited Pro Forma Financial Information

        We completed our Corporate Restructuring on December 23, 2010. The following unaudited pro forma financial information shows the pro forma effect of our Corporate Restructuring. We have not included a pro forma balance sheet since the effects of our Corporate Restructuring are reflected in the December 31, 2010 balance sheet included elsewhere in this Annual Report on Form 10-K. The unaudited pro forma statement of operations for the year ended December 31, 2010 was prepared as if our Corporate Restructuring had occurred at January 1, 2010.

        The accompanying financial information was from the historical accounting records. We made no additional pro forma adjustment to general and administrative expense since we were the operator of all acquired properties prior to their acquisition.

        The following unaudited pro forma financial statements do not purport to represent what our actual results of operations would have been if our Corporate Restructuring had occurred on January 1, 2010. The unaudited pro forma financial statements should be read in conjunction with our historical

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financial statements and related notes for the periods presented included elsewhere in this Annual Report on Form 10-K.

 
  Bonanza
Creek
Energy
Company, LLC
Period Ended
December 23,
2010
  Holmes
Eastern
Company, LLC
Period Ended
December 23,
2010
  Bonanza
Creek
Energy, Inc.
Period from
Inception
(December 23,
2010) to
December 31,
2010
  Pro Forma
Adjustments
  Bonanza
Creek
Energy, Inc.
Year Ended
December 31,
2010
 
 
   
   
   
  (unaudited)
  (unaudited)
 
 
  (in thousands, except per share data)
 

Revenues:

                               

Oil, natural gas, natural gas liquids and CO2 sales

  $ 43,506   $ 13,958   $ 1,620   $   $ 59,084  
                       

Operating expenses:

                               

Lease operating

    11,948     2,010     419         14,377  

Severance and ad valorem taxes

    1,468     834     66         2,368  

Exploration

    227     19             246  

Depreciation, depletion and amortization(1)

    12,598     3,006     436     2,816     18,856  

General and administrative

    8,375     640     324         9,339  

Cancelled private placement

    2,378                 2,378  
                       

Total operating expenses

    36,994     6,509     1,245     2,816     47,564  
                       

Income from operations

    6,512     7,449     375     (2,816 )   11,520  
                       

Other income (expense):

                               

Other income (loss)

    19     (65 )           (46 )

Write off of deferred financing costs

    (1,663 )               (1,663 )

Unrealized gain on fair value of warrant put option(2)

    34,345             (34,345 )    

Amortization of debt discount(3)

    (8,862 )           8,862      

Realized gain on settled commodity derivatives

    5,919         (47 )       5,872  

Unrealized loss in fair value of commodity derivatives

    (7,605 )       (514 )       (8,119 )

Interest expense(4)

    (18,001 )   (439 )   (57 )   17,234     (1,263 )
                       

Total other income (expense)

    4,152     (504 )   (618 )   (8,249 )   (5,219 )
                       

Income (loss) from continuing operations

    10,664     6,945     (243 )   (11,065 )   6,301  
                       

Pro forma income tax expense(5)

                      (2,319 )   (2,319 )
                             

Income (loss) from continuing operations

                          $ 3,982  
                               

(Loss) income from operations associated with oil and gas properties held for sale

    65         (13 )   (364 )   (312 )

Gain on sale of oil and gas properties

    4,055                 4,055  

Pro forma income tax (expense) benefit(5)

                (1,377 )   (1,377 )
                       

Income from discontinued operations

    4,120         (13 )   (1,741 )   2,366  
                       

Net Income

  $ 14,784   $ 6,945   $ (256 ) $ (15,125 ) $ 6,348  
                       

Basic and diluted income per share

                               

Income from continuing operations

                          $ 0.14  
                               

Income from discontinued operations

                          $ 0.08  
                               

Net income per common share

                          $ 0.22  
                               

(1)
Pro forma depletion expense gives effect to our Corporate Restructuring which required the application of purchase accounting. The expense was calculated using estimated proved reserves as of the beginning of the

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(2)
BCEC issued an aggregate of 33,089 warrants to purchase Class A units during 2006, 2007, and 2008 in connection with the sale of senior subordinated notes. These warrants included a one-time right and option to put the warrants back to BCEC at fair market value less the exercise price. This pro forma adjustment reverses the mark-to-market income for the warrant put right that was recorded during 2010. This presentation assumes that the warrants were exercised on January 1, 2010 in connection with a recapitalization.

(3)
During 2010, BCEC recorded accretion expense for the subordinated debt discount. This pro forma adjustment reverses the accretion expense recorded during 2010. This presentation assumes that the subordinated debt was paid off on January 1, 2010 in connection with a recapitalization.

(4)
This pro forma adjustment reduces interest expense by $10.9 million for BCEC interest expense that was paid in kind during 2010, a further reduction to interest expense for the amortization of debt issuance costs related to BCEC's second lien term loan that was entered into during 2010, and a further reduction for cash interest expense paid on the revolving credit facilities of BCEC and HEC and BCEC's related party note payable during 2010. This presentation assumes that BCEC's subordinated debt, the second lien term loan and BCEC's related party note payable were paid off and the balance outstanding on our revolving credit facility was reduced on January 1, 2010 in connection with a recapitalization.

(5)
Pro forma income taxes related to our pre-tax income for the year ended December 31, 2010 and is based on our expected tax rate of 36.8%.

Pro Forma Reserve Quantity and Standardized Measure Information

        The following table sets forth certain unaudited pro forma information concerning our proved oil and gas reserves giving effect to our Corporate Restructuring as if it had occurred on January 1, 2010. The following estimates of proved oil and gas reserves, both developed and undeveloped, represent interests we acquired in our Corporate Restructuring, and are located solely within the United States. Proved reserves represent estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are the quantities 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 for which relatively major expenditures are required for completion.

        The estimate of proved reserves and related valuations for the period ended December 23, 2010 was based upon a report prepared by Cawley, Gillespie & Associates, Inc. Petroleum Consultants as of December 31, 2010, adjusted for eight days of operations. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. These estimates do not include probable or possible reserves. The information provided does not represent our estimate of expected future cash flows or value of proved oil and gas reserves.

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  Oil (MBbl)   Natural Gas (MMcf)  
 
  Bonanza
Creek
Energy
Company, LLC
  Holmes
Eastern
Company, LLC
  Pro Forma
Combined
  Bonanza
Creek
Energy
Company, LLC
  Holmes
Eastern
Company, LLC
  Pro Forma
Combined
 

Balance—December 31, 2009

    15,270     6,118     21,388     27,610     16,565     44,175  

Extensions and discoveries

    1,258     50     1,308     2,249     228     2,477  

Sales of minerals in place

    (559 )       (559 )            

Production

    (595 )   (138 )   (733 )   (1,309 )   (781 )   (2,090 )

Revisions to previous estimates

    1,302     (308 )   994     12,674     5,690     18,364  
                           

Balance—December 23, 2010

    16,676     5,722     22,398     41,224     21,702     62,926  
                           

Proved developed reserves:

                                     

December 31, 2009

    4,710     1,292     6,002     7,021     5,346     12,367  

December 23, 2010

    6,465     1,734     8,199     13,703     6,413     20,116  
                           

Proved undeveloped reserves:

                                     

December 31, 2009

    10,560     4,826     15,386     20,589     11,219     31,808  

December 23, 2010

    10,211     3,988     14,199     27,521     15,289     42,810  
                           

        The following table sets forth unaudited pro forma information concerning the discounted future net cash flows from our proved oil and gas reserves as of December 23, 2010, net of income tax expense, and giving effect to our Corporate Restructuring as if it had occurred on January 1, 2010. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the Standardized Measure. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of our oil and natural gas properties.

 
  Bonanza
Creek
Energy
Company, LLC
  Holmes
Eastern
Company, LLC
  Pro Forma
Combined
 

Future cash flows

  $ 1,366,948   $ 528,802   $ 1,895,750  

Future production costs

    (434,498 )   (138,515 )   (573,013 )

Future development costs

    (222,007 )   (130,202 )   (352,209 )

Future income tax expense

    (126,005 )   (57,242 )   (183,247 )
               

Future net cash flows

    584,438     202,843     787,281  

10% annual discount for estimated timing of cash flows

    (299,329 )   (113,149 )   (412,478 )
               

Standardized Measure

  $ 285,109   $ 89,694   $ 374,803  
               

        Future cash flows as shown above were reported without consideration for the effects of derivative transactions outstanding at each period end.

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  Bonanza
Creek
Energy
Company, LLC
  Holmes
Eastern
Company, LLC
  Pro Forma
Combined
 

Beginning of period

  $ 185,704   $ 58,150   $ 243,854  

Sale of oil and gas produced, net of production costs

    (31,916 )   (11,113 )   (43,029 )

Net changes in prices and production costs

    97,744     42,468     140,212  

Extensions, discoveries and improved recoveries

    17,405     590     17,995  

Development costs incurred

    21,615     9,342     30,957  

Changes in estimated development cost

    (30,350 )   (14,006 )   (44,356 )

Sales of mineral in place

    (10,799 )       (10,799 )

Revisions of previous quantity estimates

    65,959     11,833     77,792  

Net change in income taxes

    (38,932 )   (10,019 )   (48,951 )

Accretion of discount

    20,368     7,183     27,551  

Changes in production rates and other

    (11,689 )   (4,734 )   (16,423 )
               

End of period

  $ 285,109   $ 89,694   $ 374,803  
               

        Average wellhead prices inclusive of adjustments for quality and location used in determining future net revenues related to the Standardized Measure calculation as of December 23, 2010 were calculated using the first-day-of-the-month price for each of the 12 months that made up the reporting period.

 
  Bonanza
Creek
Energy
Company, LLC
  Holmes
Eastern
Company, LLC
 

Oil (per Bbl)

  $ 74.77   $ 75.33  

Gas (per Mcf)

  $ 4.72   $ 4.98  

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."

        Despite the uncertainty surrounding the global economy and continued volatility in commodity prices, we believe our portfolio positions us well moving forward. Our operations are focused in the Wattenberg Field in the DJ Basin of Colorado and the Cotton Valley sands of southern Arkansas. The low risk, oily and stable production profile of our Arkansas assets provides a strong cash flow base from which to develop the Niobrara and Codell formations in Colorado. Our corporate strategy is to create shareholder value by increasing production in our current assets, while opportunistically seeking strategic acquisitions in other high return basins across the United States where we can apply our core competencies of horizontal drilling and fracture stimulation. We maintain a high working interest in our properties and operate all of our proved reserves.

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Financial and Operating Highlights

        Our 2012 financial results included:

        We delivered significant growth in 2012. Operational highlights for 2012 included the following:

Outlook for 2013

        We continue to monitor the outlook for the global economy and numerous critical factors including the United States federal budget deficit and long-term fiscal situation, the European debt crisis, and their potential impacts on global economic growth and commodity prices. Because the global economic outlook and commodity price environment are uncertain, we have planned a flexible capital spending program. We estimate our total capital expenditures for 2013 to be $394 million, allocated approximately 80% to the Wattenberg Field and 20% 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 budget as appropriate. This capital investment is expected to produce 2013 average sales volumes of 14,500 to 16,000 Boe/d, while maintaining a strong oil and liquids profile.

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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 of Part II of this Annual Report on Form 10-K. Comparative results of operations for the period indicated are discussed below.

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

 
  Year
Ended
December 31,
2012
  Year
Ended
December 31,
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 %
                     

Sales volumes:

                         

Crude oil (MBbls)

    2,191.0     887.4     1,303.6     147 %

Natural gas (MMcf)

    5,473.2     2,773.1     2,700.1     97 %

Natural gas liquids (MBbls)

    284.7     183.8     100.9     55 %
                     

Crude oil equivalent (MBoe)(1)

    3,387.9     1,533.4     1,854.5     121 %
                     

Average Sales Prices (before hedging)(2):

                         

Crude oil (per Bbl)

  $ 89.08   $ 89.67   $ (0.59 )   (1 )%

Natural gas (per Mcf)

    3.62     4.85     (1.23 )   (25 )%

Natural gas liquids (per Bbl)

    55.54     67.23     (11.69 )   (17 )%

Crude oil equivalent (per Boe)(1)

    68.12     68.72     (0.60 )   (1 )%

Average Sales Prices (after hedging)(2):

                         

Crude oil (per Bbl)

  $ 88.40   $ 85.51   $ 2.89     3 %

Natural gas (per Mcf)

    3.76     5.09     (1.33 )   (26 )%

Natural gas liquids (per Bbl)

    55.54     67.23     (11.69 )   (17 )%

Crude oil equivalent (per Boe)(1)

    67.91     66.75     1.16     2 %

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

(2)
Although we do not designate our derivatives as cash flow hedges for financial statement purposes, the derivatives do economically hedge the price we receive for crude oil and natural gas.

        Revenues increased by 119%, to $231.2 million for the year ended December 31, 2012 compared to $105.7 million for the year ended December 31, 2011. Oil, natural gas, and natural gas liquids production increased 147%, 97%, and 55%, respectively, during the year ended December 31, 2012, as compared to the year ended December 31, 2011. During the period from January 1, 2012 through December 31, 2012, we drilled 108 gross (104.7 net) wells in the Rockies and 42 gross 37.2 wells in southern Arkansas. The increased volumes are a direct result of the $165.5 million expended for drilling and completion and gas plant capital expenditures during the year ended December 31, 2011, and the $340.8 million expended during the year ended December 31, 2012. Oil prices were commensurate period over period and increased oil volumes accounted for nearly all of the $115.6 million of the total $125.5 million increase in revenues for the Company for the year ended December 31, 2012 compared to the same period in 2011. Natural gas volumes increased by 97% in

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2012, but were partially offset by a sales price decline of 25% from $4.85 per Mcf to $3.62 per Mcf for these one year periods and accounted for $6.4 million of the total $125.5 million increase in revenues for the year ended December 31, 2012. Natural gas liquid volumes increased by 55% in 2012, but were partially offset by a sales prices decline of 17% from $67.23 per Bbl to $55.54 per Bbl for these one year periods and accounted for $3.5 million of the total $125.5 million increase in revenues for the year ended December 31, 2012. Our Wattenberg Field natural gas is sold without processing and sells at a premium due to its very high BTU content. Our production of oil, natural gas, and natural gas liquids for year ended December 31, 2012 was approximately 65%, 27% and 8%, respectively, of total production.

 
  Year
Ended
December 31,
2012
  Year
Ended
December 31,
2011
  Change   Percent
Change
 

Expenses (in thousands, except percentages):

                         

Lease operating

  $ 30,695   $ 18,253   $ 12,442     68 %

Severance and ad valorem taxes

    13,674     5,919     7,755     131 %

General and administrative

    31,405     17,613     13,792     78 %

Depreciation, depletion and amortization

    66,202     28,014     38,188     136 %

Exploration

    10,715     877     9,838     1,122 %

Impairment of oil and gas properties

    611     623     (12 )   (2 )%
                     

Operating expenses

  $ 153,302   $ 71,299   $ 82,003     115 %
                     

Expenses per Boe:

                         

Lease operating

  $ 9.06   $ 11.90   $ (2.84 )   (24 )%

Severance and ad valorem taxes

    4.04     3.86     0.18     5 %

General and administrative

    9.27     11.49     (2.22 )   (19 )%

Depreciation, depletion and amortization

    19.54     18.27     1.27     7 %

Exploration

    3.16     0.57     2.59     454 %

Impairment of oil and gas properties

    0.18     0.41     (0.23 )   (56 )%
                     

Operating expenses

  $ 45.25   $ 46.50   $ (1.25 )   (3 )%
                     

        Lease Operating Expense.    Our lease operating expenses increased $12.4 million, or 68%, to $30.7 million for the year ended December 31, 2012 from $18.3 million for the year ended December 31, 2011 and decreased on an equivalent basis from $11.90 per Boe to $9.06 per Boe. The increase in lease operating expense was related to increased production volumes attributable to our drilling program and the operation of an additional gas plant that was constructed during 2011 that came on line during September of 2011. Gas plant operating expense, which is a component of lease operating expense, increased $1.1 million, or 15%, to $8.4 million for the year ended December 31, 2012 from $7.3 million for the year ended December 31, 2011. A portion of the increase in gas plant operating expense was related to the replacement of a heat exchanger which cost approximately $0.6 million to procure and install. During the year ended December 31, 2012, well servicing, rental equipment, pumping and gauging, and insurance expenses were $8.3 million, $1.7 million, $0.4 million and $0.6 million higher, respectively, than the year ended December 31, 2011. The decrease in lease operating expense on an equivalent basis was primarily related to our transition from vertical wells to horizontal wells in the Wattenberg Field during 2012.

        Severance and ad valorem taxes. Our severance and ad valorem taxes increased $7.8 million, or 131%, to $13.7 million for the year ended December 31, 2012 from $5.9 million for the year ended December 31, 2011. The increase was primarily related to a 121% increase in production volumes and

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higher ad valorem tax assessments. The increase in severance and ad valorem taxes on a Boe basis for the year ended December 31, 2012 as compared to the year ended December 31, 2011 was related to oil severance taxes and ad valorem taxes that were $4.2 million and $3.2 million, respectively, higher than the comparable period in the previous year.

        General and administrative.    Our general and administrative expense increased $13.8 million, or 78%, to $31.4 million for the year ended December 31, 2012 from $17.6 million for the year ended December 31, 2011. During the year ended December 31, 2012, wages, benefits and employee placement fees were $10.2 million higher than the year ended December 31, 2011 due to our headcount increasing as the result of our accelerated drilling program and the addition of accounting, legal and IT positions that were previously outsourced. During the year ended December 31, 2012, accounting fees were $0.4 million higher due to a one-time payment that was made to our outsource accounting provider to terminate our agreement with them. Also during the year ended December 31, 2012, legal fees and franchise taxes were $2.1 million and $0.5 million higher, respectively. The majority of the increased general and administrative expense is due to hiring a large number of personnel to support our growth and the regulatory compliance obligations of a newly public company and legal fees associated with arbitration related to claims of a former chairman of BCEC. See Item 3 "Legal Proceedings."

        Depletion, depreciation and amortization.    Our depletion, depreciation and amortization expense increased $38.2 million, or 136%, to $66.2 million for the year ended December 31, 2012 from $28.0 million for the year ended December 31, 2011. Our depreciation, depletion and amortization expense per Boe produced increased $1.27 to $19.54 for the year ended December 31, 2012 as compared to $18.27 for the year ended December 31, 2011. This increase was primarily the result of a 121% increase in production period over period that was compounded by proved reserve and proved developed reserve volume growth that was not commensurate with the costs additions to the depletion base. At December 31, 2012, we revised our proved reserves downward by 6,938 MBoe due primarily to a combination of eliminating 50 locations from proved undeveloped reserves as a result of changes in focus from vertical to horizontal development and lower performance than expected from our vertical wells in the Wattenberg Field.

        Impairment of oil and gas properties.    The Company recorded $0.6 million of proved property impairment in one non-core Field in southern Arkansas for the year ended December 31, 2012. The Company recorded $0.6 million of proved property impairment in one non-core Field in southern Arkansas for the year ended December 31, 2011.

        Exploration costs.    Our exploration expense increased $9.8 million, or 1,122%, to $10.7 million in the year ended December 31, 2012 from $0.9 million in the year ended December 31, 2011. During the year ended December 31, 2012 the following items were charged to exploration expense: a seismic acquisition project in the amount of $2.0 million was conducted in the North Park Basin of Colorado; three exploratory locations in the North Park basin in the amount of $8.4 million were written off; and delay rentals in the amount of $0.3 million were paid. During the year ended December 31, 2011, our exploration costs consisted primarily of the acquisition of 7,700 acres of 3-D seismic data on the eastern edge of the Wattenberg Field in Weld County Colorado to help evaluate our Niobrara oil shale acreage.

        Interest expense.    Our average debt outstanding for the year ended December 31, 2012 was $74.7 million as compared to $95.3 million for the year ended December 31, 2011. Our interest expense for the year ended December 31, 2012 was commensurate with the year ended December 31, 2011 due to accretion expense in the amount of $0.3 million related to our contractual obligation for the lease acquisition in the Wattenberg Field and fees of $50,000 related to our $48 million letter of credit obligation which secures the acquisition.

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        Realized loss on settled commodity derivatives.    Realized losses on oil and gas hedging activities decreased by $2.3 million from a loss of $3.0 million for the year ended December 31, 2011 to a loss of $0.7 million for the year ended December 31, 2012. The decrease in realized cash hedge loss period over period was related to oil and natural gas prices that were one percent and 25% lower, respectively, during the year ended December 31, 2012 as compared to the year ended December 31, 2011.

        Income tax expense.    Our estimate for federal and state income taxes for the year ended December 31, 2012 was $30.0 million from continuing operations as compared to $12.9 million for the year ended December 31, 2011. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. During the year ended December 31, 2012, the estimated effective tax rate was revised to reflect a 35% rate for federal income taxes. The Company believes that this rate more appropriately reflects the future federal rate on future earnings. The increase in the effective tax rate was applied to the January 1, 2012 deferred income tax liability resulting in an increase to the net deferred tax liability and deferred income tax expense of $1.2 million. Our effective tax rates differ from the U.S. statutory income tax rate primarily due to the effects of state income taxes.

Year Ended December 31, 2011 Compared to Period Ended December 23, 2010

        We completed our Corporate Restructuring on December 23, 2010. The operating results presented below for the audited period ended December 23, 2010 exclude the audited eight-day period from inception through December 31, 2010. The operating results of BCEI for the eight-day period from December 23, 2010 through December 31, 2010 were net revenues, operating expense, and income from operations of approximately $1.6 million, $1.2 million, and $0.4 million, respectively, and did not include transactions that were inconsistent or unusual when compared to the results for the audited period ended December 23, 2010. Other expense during this period was primarily comprised of a $0.5 million unrealized loss in the fair value of commodity derivatives.

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  Year
Ended
December 31,
2011
  Period
Ended
December 23,
2010
  Change   Percent
Change
 

Revenues (in thousands, except percentages):

                         

Crude oil sales

  $ 79,568   $ 29,609   $ 49,959     169 %

Natural gas sales

    13,442     6,226     7,216     116 %

Natural gas liquids sales

    12,358     7,088     5,270     74 %

CO2 sales

    356     583     (227 )   (39 )%
                     

Product revenues

  $ 105,724   $ 43,506   $ 62,218     143 %
                     

Sales volumes:

                         

Crude oil (MBbls)

    887.4     401.4     486.0     121 %

Natural gas (MMcf)

    2,773.1     1,308.5     1,464.6     112 %

Natural gas liquids (MBbls)

    183.8     126.5     57.3     45 %
                     

Crude oil equivalent (MBoe)(1)

    1,533.4     746.0     787.4     106 %
                     

Average Sales Prices (before hedging)(2):

                         

Crude oil (per Bbl)

  $ 89.67   $ 73.75   $ 15.92     22 %

Natural gas (per Mcf)

    4.85     4.76     0.09     2 %

Natural gas liquids (per Bbl)

    67.23     56.04     11.19     20 %

Crude oil equivalent (per Boe)(1)

    68.72     57.54     11.18     19 %

Average Sales Prices (after hedging)(2):

                         

Crude oil (per Bbl)

  $ 85.51   $ 75.69   $ 9.82     13 %

Natural gas (per Mcf)

    5.09     5.01     0.08     2 %

Natural gas liquids (per Bbl)

    67.23     56.04     11.19     20 %

Crude oil equivalent (per Boe)(1)

    66.75     59.02     7.73     13 %

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

(2)
Although we do not designate our derivatives as cash flow hedges for financial statement purposes, the derivatives do economically hedge the price we receive for crude oil and natural gas.

        Revenues increased by 143% to $105.7 million for the year ended December 31, 2011 compared to $43.5 million for the period ended December 23, 2010. Oil production increased 121% and natural gas production increased 112% during the year ended December 31, 2011 as compared to the period ended December 23, 2010. The most significant components of the increased production were related to an increased drilling program and the acquisition of HEC, which occurred on December 23, 2010. Our product revenues and production for the period ended December 23, 2010 excluded HEC revenues and production of $14.0 million and 268.2 Mboe, respectively. The increase in net revenues was also the result of a 22% increase in oil prices with a 2% increase in natural gas prices, respectively, for an overall increase of 19% per Boe. Also contributing to the increased revenue was a 106% increase in production attributable to our drilling program. During 2011, we drilled and completed approximately 100 wells as compared to 42 wells during 2010.

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  Year
Ended
December 31,
2011
  Period
Ended
December 23,
2010
  Change   Percent
Change
 

Expenses (in thousands, except percentages)

                         

Lease operating

  $ 18,253   $ 11,948   $ 6,305     53 %

Severance and ad valorem taxes

    5,919     1,468     4,451     303 %

General and administrative

    17,613     8,375     9,238     110 %

Depreciation, depletion and amortization

    28,014     12,598     15,416     122 %

Exploration

    877     227     650     286 %

Impairment of oil and gas properties

    623         623     100 %

Cancelled private placement

        2,378     (2,378 )   (100 )%
                     

Operating expenses

  $ 71,299   $ 36,994   $ 34,305     93 %
                     

Expenses per Boe:

                         

Lease operating

  $ 11.90   $ 16.02   $ (4.12 )   (26 )%

Severance and ad valorem taxes

    3.86     1.97     1.89     96 %

General and administrative

    11.49     11.23     0.26     2 %

Depreciation, depletion and amortization

    18.27     16.89     1.38     8 %

Exploration

    0.57     0.30     0.27     90 %

Impairment of oil and gas properties

    0.41         0.41     100 %

Cancelled private placement

        3.19     (3.19 )   (100 )%
                     

Operating expenses

  $ 46.50   $ 49.60   $ (3.10 )   (6 )%
                     

        Lease operating expenses.    Our lease operating expenses increased $6.3 million, or 53%, to $18.3 million for the year ended December 31, 2011 from $12.0 million for the period ended December 23, 2010 and decreased on an equivalent basis from $16.02 per Boe to $11.90 per Boe. The increase in lease operating expense was related to increased production volumes due to the acquisition of HEC on December 23, 2010 and increased production attributable to our drilling program. The period ended December 23, 2010 does not include HEC lease operating expenses, which were $2.0 million. During the year ended December 31, 2011, gauging and pumping, compressor rentals, well servicing and testing, and gas plant maintenance and repairs were $1.8 million, $1.0 million, $1.0 million and $0.8 million higher, respectively, than the period ended December 23, 2010. The decrease in lease operating expenses on an equivalent basis was primarily related to the lower operating costs of the wells acquired from HEC. On an equivalent basis, the lease operating expense for the wells acquired from HEC was $7.50 per Boe during the period ended December 23, 2010 as compared to the lease operating expense for BCEC's wells which was $16.02 per Boe during the period ended December 23, 2010.

        Severance and ad valorem taxes.    Our severance and ad valorem taxes increased $4.4 million, or 303%, to $5.9 million for the year ended December 31, 2011 from $1.5 million for the period ended December 23, 2010 and increased on a Boe basis from $1.97 to $3.86. The increase was primarily related to a 106% increase in production volumes and a 19% increase in realized prices per Boe during the year ended December 31, 2011 as compared to the period ended December 23, 2010, and an increase in ad valorem tax of $2.4 million due to higher assessment values. The period ended December 23, 2010 does not include HEC severance and ad valorem tax, which were $0.8 million. The increase in severance and ad valorem taxes on a Boe basis for the year ended December 31, 2011 as compared to the period ended December 23, 2010 was primarily related to higher ad valorem taxes of $2.4 million and true-ups of estimated severance taxes based on Colorado severance tax returns for 2009 and 2010 that were filed during April of the subsequent year. The revision of estimated severance

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taxes based on the final Colorado severance tax returns resulted in a decrease in severance tax expense in 2010 and an increase in severance tax expense in 2011.

        General and administrative.    Our general and administrative expense increased $9.2 million, or 110%, to $17.6 million for the year ended December 31, 2011 from $8.4 million for the period ended December 23, 2010. The period ended December 23, 2010 does not include HEC's general and administrative expenses, which were $0.6 million. During the year ended December 31, 2011 wages and benefits and legal and professional services fees were $2.1 million and $2.0 million, respectively, higher than the previous period. The increase in wages and benefits is related to increased head count and $1.1 million of the increase in legal and professional services fees were related to investigations and transactions not consummated. In connection with our IPO, the Company distributed 243,945 fully vested shares of common stock previously held in trust to our employees and recorded a $4.1 million stock compensation charge. In addition, the Company distributed the remaining 3,400 shares of our former Class B common stock to our employees. In connection with our IPO, all issued and outstanding shares of our former Class B Common Stock converted into 437,787 shares of restricted common stock, vesting over a three year period and we recorded a $0.1 million stock compensation charge. We expect to recognize employee stock compensation expense relating to these grants during the years ended December 31, 2012, 2013, and 2014 of approximately $2.5 million, $2.5 million, and $2.3 million, respectively, assuming no forfeitures.

        Depreciation, depletion and amortization.    Our depreciation, depletion and amortization expense increased $15.4 million, or 122%, to $28.0 million for the year ended December 31, 2011 from $12.6 million for the period ended December 23, 2010. This increase was the result of a 106% increase in production and the step up in basis that was recorded in oil and gas properties as a result of our Corporate Restructuring. In connection with our Corporate Restructuring, all of our oil and gas Fields were adjusted to fair value based on each Field's discounted future net cash flows, which resulted in basis increases to the Mid-Continent and Rocky Mountain Fields with corresponding decreases to the California Fields. Our depreciation, depletion and amortization expense per Boe increased by $1.38, or 8%, to $18.27 for the year ended December 23, 2011 as compared to $16.89 for the period ended December 23, 2010.

        Exploration.    Our exploration expense increased $0.7 million, or 286%, to $0.9 million for the year ended December 31, 2011 from $0.2 million in the period ended December 23, 2010. The increase in exploration expense was primarily related to the acquisition of 7,700 acres of 3-D seismic data on the eastern edge of the Wattenberg Field in Weld County, Colorado to help evaluate our Niobrara oil shale acreage.

        Impairment of Proved Properties.    The Company recorded $0.6 million of proved property impairments in one non-core Field in southern Arkansas for the year ended December 31, 2011. The impairment of the non-core Field in Southern Arkansas was related to the loss of a lease. There were no impairments of proved properties for the period ended December 23, 2010.

        Interest expense.    Our interest expense decreased $14.0 million, or 78%, to $4.0 million for the year ended December 31, 2011 from $18.0 million for the period ended December 23, 2010. The decrease resulted from the application of $182 million of cash proceeds from our Corporate Restructuring to repay the second lien term loan, the senior subordinated notes and a related party note payable, and to repay $29 million of principal under our credit facility on December 23, 2010. Average debt outstanding for the year ended December 31, 2011 was $95.3 million as compared to $215.3 million for the period ended December 23, 2010.

        Realized gain (loss) on settled commodity derivatives.    Realized gains on oil and gas hedging activities decreased by $8.9 million from a gain of $5.9 million for the period ended December 23, 2010 to a loss of $3.0 million for the year ended December 31, 2011. Because we assumed a derivative in a

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liability position in 2008, our realized gain was higher by $4.8 million upon the settlement of this portion of the assumed derivative in the period ended December 23, 2010. The decrease from a realized cash hedge gain to a loss period over period was primarily related to commodity prices that were 19% higher during the year ended December 31, 2011 as compared to the period ended December 23, 2010.

        Income Tax Expense.    Our predecessor, BCEC, was not subject to federal and state income taxes. As a result of our Corporate Restructuring, we were organized as a Delaware corporation subject to federal and state income taxes. During the year ended December 31, 2011, the estimated effective tax rate was revised to reflect significant capital expenditures in Arkansas and the effective tax rate increased from 36.87% to 37.98%. The increase in the effective tax rate was applied to the January 1, 2011 deferred income tax liability resulting in an increase to the net deferred tax liability and deferred income tax expense of $2.4 million with an additional $10.5 million incurred for federal and state income taxes for the year ended December 31, 2011 for a total deferred income tax expense in our consolidated statement of operations of $12.9 million. We are allowed to deduct various items for tax reporting purposes that are capitalized for purposes of financial statement presentation. All income taxes for the year ended December 31, 2011 were deferred.

        Change in fair value of warrant put option.    The fair value of the warrant put option decreased $34.3 million, or 100%, to $0 for the year ended December 31, 2011 from a gain of $34.3 million for the period ended December 23, 2010. The decrease resulted from the exercise of the warrants on December 23, 2010 in connection with our Corporate Restructuring.

        Accretion of debt discount.    Our expense for accretion of debt discount decreased $8.9 million, or 100%, to $0 for the year ended December 31, 2011 from $8.9 million for the period ended December 23, 2010. The decrease resulted from the retirement of BCEC's senior subordinated notes on December 23, 2010 in connection with our Corporate Restructuring.

Results for Discontinued Operations

        During June of 2012, the Company began marketing, with an intent to sell, all of our oil and gas properties in California. Assets are classified as held for sale when the Company commits to a plan to sell the assets and there is reasonable certainty that the sale will take place within one year. The Company determined that our intent to sell these properties qualifies for discontinued operations accounting and these assets are presented as discontinued operations in the Company's statements of operations.

        The operating results before income taxes for our California properties for the year ended December 31, 2012 were net revenues, operating expenses, and loss from discontinued operations of $5.4 million, $6.3 million, and $0.9 million, respectively, as compared to net revenues, operating expenses, and loss from discontinued operations of $6.7 million, $10.3 million, $3.6 million, for the year ended December 31, 2011. Operating expenses for the year ended December 31, 2012 included impairments in the amount of $1.6 million. Sales volumes for the years ended December 31, 2012 and 2011 were 53.7 MBbls and 66.1 MBbls, respectively.

        The operating results before income taxes for our California properties for the year ended December 31, 2011 were net revenues, operating expenses, and loss from discontinued operations of $6.7 million, $10.3 million, and $3.6 million, respectively, as compared to net revenues, gain on the sale of the Jasmin property, operating expenses, and gain from discontinued operations of $4.8 million, $4.1 million, $4.7 million, and $0.1 million for the period ended December 23, 2010. Operating expenses for the year ended December 31, 2011 included impairments in the amount of $3.4 million. Sales volumes for the year ended December 31, 2011 and period ended December 23, 2010 were 66.1 MBbls and 67.6 MBbls, respectively.

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        See Note 4 to our consolidated financial statements included in Item 8 of Part II of this Annual Report on Form 10-K.

Liquidity and Capital Resources

        Our primary sources of liquidity to date have been proceeds from our initial public offering, Corporate Restructuring, capital contributions from investors, borrowings under our credit facility and cash flows from operations and proceeds from the sale of non-core properties. Our primary use of capital has been for the acquisition and development of oil and natural gas properties.

        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. During 2012, we sold a majority of our properties in California, for approximately $9.3 million in aggregate.

        On July 31, 2012, we acquired leases in the Wattenberg Field from the State of Colorado, State Board of Land Commissioners. We paid approximately $12 million at closing and will pay approximately $12 million on July 31st of each of the next four years. These future payments are secured by a letter of credit which reduced our availability under the borrowing base by $48 million as of December 31, 2012.

        On April 6, 2012, the administrative agent under our credit facility was changed to KeyBank, National Association. On May 8, 2012, we entered into an amendment with the lenders under our credit facility to, among other things, and (i) increase our credit facility to $600 million, and (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect our operations and capital budgets. On October 30, 2012 our borrowing base was increased to $325 million, and as of December 31, 2012, we had $158.0 million outstanding, $48.0 million of letters of credit issued, and $119.0 million of borrowing capacity available under our credit facility. Our weighted-average interest rate on borrowings from our credit facility was 4.06% during the year ended December 31, 2012.

        On December 15, 2011 the Company sold 10,000,000 shares of our common stock in our IPO at $17.00 per share, less $1.105 per share for underwriting discounts and commissions. Other expenses related to the issuance and distribution of these shares were approximately $3 million.

        We expect that in the future our commodity derivative positions will help us stabilize a portion of our expected cash flows from operations despite potential declines in the price of oil and natural gas. Please see "Item 7A.—Quantitative and Qualitative Disclosures on Market Risks."

        We believe that the combination of our cash flow from operating activities, potential access to debt and capital markets, our current liquidity level and our ability to modify our future capital expenditure programs, will allow us to comply with all of our debt covenants, and meet the obligations from our ongoing operations.

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        The following table summarizes our cash flows and other financial measures for the periods indicated.

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

Financial Measures:

                         

Net cash provided by operating activities

  $ 156,910   $ 57,603   $ 1,633   $ 22,759  

Net cash provided by (used in) investing activities

    (304,551 )   (158,902 )   (817 )   (32,127 )

Net cash provided by (used in) financing activities

    149,819     103,389         9,297  

Cash and cash equivalents

    4,268     2,090         2,450  

Acquisitions of oil and gas properties

    13,920     1,810         1,066  

Exploration and development of oil and gas properties and investment in gas processing facility

    297,114     156,871     817     34,728  

        Net cash provided by operating activities was $156.9 million for the year ended December 31, 2012, compared to $57.6 million provided by operating activities for the year ended December 31, 2011. The increase in cash flows from operating activities resulted primarily from an increase in revenues from increased production. Cash provided by changes in working capital for the year ended December 31, 2012 was $0.7 million as compared to cash utilized by changes in working capital in the amount of $7.0 million for the comparable period during 2011. The increase in working capital of $0.7 million for the year ended December 31, 2012 is comprised primarily of increases in accounts receivable and prepaid expenses and other assets in the amount of $21.9 million offset by an increase in accounts payables and accrued liabilities (exclusive of capital accruals) of $22.8 million due primarily to timing of accounts payable check distributions.

        Net cash provided by operating activities was $57.6 million for the year ended December 31, 2011, compared to $22.8 million provided by operating activities for the period ended December 23, 2010. The increase in operating activities resulted primarily from an increase in revenues, increased production, and increased commodity prices offset by cash utilized in connection with changes in working capital when comparing the periods. Cash utilized by changes in working capital for the year ended December 31, 2011 was $7.0 million as compared to $5.8 million that was provided by changes in working capital for the comparable period during 2010. Decreases in working capital of $7.0 million for the year ended December 31, 2011 is comprised primarily of increases in accounts receivable of $11.7 million offset by an increase in accounts payables and accrued liabilities (exclusive of capital accruals) of $6.0 million due primarily to timing of accounts payable check distributions.

        Expenditures for development of oil and natural gas properties and natural gas plants are the primary use of our capital resources. Net cash used in investing activities for the year ended December 31, 2012 was $304.6 million, compared to $158.9 million cash used in investing activities for the year ended December 31, 2011. The increase was primarily due to expenditures of $13.9 million for the acquisition of oil and gas properties, $281.3 million for exploration and development of oil and gas properties, $15.8 million for natural gas plant costs, and $3.1 million for non oil and gas property

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additions, partially offset by $9.3 million of proceeds received for the sale of non core oil and gas properties in California.

        For the year ended December 31, 2011, net cash used in investing activities was $158.9 million for the development of oil and natural gas properties, including $22.7 million for a natural gas plant and other facilities and $1.8 million for the acquisition of oil and gas properties. For the period ended December 23, 2010, excluding our Corporate Restructuring, net cash used in investing activities was $32.1 million, of which we spent approximately $1.1 million on acquisitions, $34.7 million for the exploration and development of oil and gas properties including $4.0 million for a natural gas plant and other facilities, advanced $3.7 million to fund HEC's exploration and development program, offset by the receipt of proceeds in the amount of $7.5 million for the sale of the Jasmin Field. In connection with our Corporate Restructuring, $59 million in cash along with common stock valued at $21.1 million was used to acquire HEC.

        Net cash flow provided by financing activities for the year ended December 31, 2012 was $149.8 million primarily related to revolver borrowings in the amount of $151.4 million partially offset by $0.5 million that was spent to satisfy employee tax withholdings for restricted stock that vested during the year and deferred financing costs in the amount of $1.1 million. Net cash flow provided by financing activities for the year ended December 31, 2011 was $103.4 million primarily related to the sale of common stock, net of offering expenses, in the amount of $155.9 million offset by a net reduction in debt from payments on our credit facility in the amount of $48.8 million. Cash used for deferred financing costs was approximately $2.3 million and we spent $1.4 million to satisfy employee tax withholdings related to common stock that was granted during the period. Net cash provided by financing, excluding Corporate Restructuring, was $9.3 million for the period ended December 23, 2010, primarily related to net borrowings in the amount of $12.7 million offset by deferred financing charges in the amount of $3.4 million.

        In connection with our Corporate Restructuring, we received net proceeds of approximately $265 million from the sale of shares of our common stock to West Face Capital and to certain clients of AIMCo. Proceeds from this transaction in the amount of $59 million along with common stock valued at $21.1 million was used to acquire HEC; $17.3 million of the proceeds were used for debt extinguishment penalties; and $182 million was used to retire BCEC's second lien term loan, the senior subordinated notes and a related party note payable, and to make a $29 million principal payment on BCEC's line of credit.

        Senior Secured Revolving Credit Facility—On April 6, 2012, the administrative agent under our credit facility was changed to Key Bank National Association. On May 8, 2012, we entered into an amendment with the lenders under our credit facility to, among other things, (i) increase our credit facility to $600 million, and (ii) make changes in the covenant applicable to hedging to allow greater flexibility for management to implement comprehensive hedging plans to adequately protect the Company's operations and capital budgets. The Revolver provides for interest rates plus an applicable margin to be determined based on LIBOR or a bank base rate ("Base Rate"), at the Company's election. LIBOR borrowings bear interest at LIBOR plus 1.75% to 2.75% depending on the utilization level, and the Base Rate borrowings bear interest at the "Bank Prime Rate," as defined, plus .75% to 1.75%.

        Our borrowing base under the credit agreement, which was $325 million as of December 31, 2012, is redetermined semiannually by May 15 and November 15 and may be redetermined up to one additional time between such scheduled determinations upon our request or upon the request of the

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required lenders (defined as lenders holding 662/3% of the aggregate commitments). The borrowing base is determined by the value of our oil and gas reserves. The borrowing base is redetermined (i) in the sole discretion of the administrative agent and all of the lenders, (ii) in accordance with their customary internal standards and practices for valuing and redetermining the value of oil and gas properties in connection with reserve based oil and natural gas loan transactions, (iii) in conjunction with the most recent engineering report and other information received by the administrative agent and the lenders relating to our proved reserves and (iv) based upon the estimated value of our proved reserves as determined by the administrative agent and the lenders.

        As of December 31, 2012, we had approximately $158 million outstanding under our credit facility. As of February 28, 2013, we had approximately $191.5 million outstanding under our credit facility. The credit facility matures on September 15, 2016. Amounts borrowed and repaid under the credit facility may be reborrowed. The credit facility may be used only to finance development of oil and gas properties, for working capital and for other general corporate purposes.

        Our obligations under the credit facility are secured by first priority liens on all of our property and assets (whether real, personal, or mixed, tangible or intangible), including our proved reserves and our oil and gas properties (which term is defined to include fee mineral interests, term mineral interests, leases, subleases, farm-outs, royalties, overriding royalties, net profit interests, carried interests, production payments, back in interests and reversionary interests). The facility is guaranteed by us and all of our direct and indirect subsidiaries.

        Interest under the credit facility is generally determined by reference to either, at our option:

The applicable margin varies on a daily basis based on the percentage outstanding under the borrowing base. We incur quarterly commitment fees based on the unused amount of the borrowing base ranging from 0.375% and 0.50% per annum. We may prepay loans under the credit facility at any time without premium or penalty (other than customary LIBOR breakage costs).

        The credit facility contains various covenants limiting our ability to:

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        The credit facility also contains covenants requiring us to maintain:

As of December 31, 2012, we were in compliance with these ratios. If an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity of the loan and exercise other rights and remedies.

        The credit agreement contains customary events of default, including:

Contractual Obligations

        We have the following contractual obligations and commitments as of December 31, 2012 (in thousands):

 
  Payment by Period  
Contractual Obligation
  Total   1 Year
or Less
  2 - 3 Years   4 - 5 Years   More Than
5 Years
 

Wattenberg Field Lease Acquisition

  $ 48,000   $ 12,000   $ 24,000   $ 12,000   $  

Credit facility(1)

    158,000             158,000      

Operating leases(2)

    6,989     1,375     3,037     2,109     468  

Asset retirement obligations(3)

    7,734     400     452         6,882  
                       

Total

  $ 220,723   $ 13,775   $ 27,489   $ 172,109   $ 7,350  
                       

(1)
Amount excludes interest on our credit facility as both the amount borrowed and the applicable interest rate is variable.

(2)
See Note 8 to our consolidated financial statements for a description of operating leases.

(3)
Amount represents our estimate of future retirement obligations on a discounted basis unless otherwise noted. Because these costs typically extend many years into the future, management

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        Oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized at cost when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive. All capitalized well costs and other associated costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.

        Costs of retired, sold or abandoned properties that constitute a part of an amortization base (partial Field) are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate for an entire Field, in which case a gain or loss is recognized currently. Gains or losses from the disposal of properties are recognized currently.

        Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and natural gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.

        Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs. The expensing of the unproved lease acquisition costs is recorded as impairment expense in the statement of operations in our consolidated financial statements. Lease acquisition costs

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related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.

        For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.

        Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. While the SEC has recently adopted rules which allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC's revised rules define proved reserves as the 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. Our independent engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each Field. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

        Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.

        Revenue from our interests in producing wells is recognized when the product is delivered, at which time the customer has taken title and assumed the risks and rewards of ownership, and collectability is reasonably assured. Substantially all of our production is sold to purchasers under short-term (less than 12 month) contracts at market-based prices. The sales prices for oil and natural gas are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment.

        Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.

        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.

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We estimate the expected undiscounted future cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved properties will be recorded.

        We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value.

        We have historically recognized impairment expense for unproved properties at the time when the lease term has expired or sooner if, in management's judgment, the unproved properties have lost some or all of their carrying value. We consider the following factors in our assessment of the impairment of unproved properties:

        The assessment of unproved properties to determine any possible impairment requires significant judgment.

        We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The asset retirement obligation ("ARO") for oil and gas properties represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized cost is depreciated on the unit-of-production method. The accretion expense is recorded as a component of Depreciation, depletion and amortization in our Consolidated Statement of Operations.

        We determine the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing, existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair

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value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.

        We record all derivative instruments on the balance sheet as either assets or liabilities measured at their estimated fair value. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into such instruments for speculative trading purposes. Derivative instruments are adjusted to fair value every accounting period. Realized gains and realized losses from the settlement of commodity derivative instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled commodity derivative instruments are reported under Other Income (Expense) in our Consolidated Statement of Operations.

        Restricted Stock Awards.    We recognize compensation expense for all restricted stock awards made to employees and directors. Stock-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense on a straight-line basis over the requisite service period, which is generally the vesting period. The fair value of restricted stock grants is based on the value of our common stock on the date of grant. Assumptions regarding forfeiture rates are subject to change. Any such changes could result in different valuations and thus impact the amount of stock-based compensation expense r