10-K 1 a2207598z10-k.htm 10-K

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



FORM 10-K

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



For the fiscal year ended December 31, 2011
Commission file number: 001-32920



LOGO

(Exact name of registrant as specified in its charter)

Yukon Territory
(State or other jurisdiction of
incorporation or organization)
  N/A
(I.R.S. Employer
Identification No.)

1625 Broadway, Suite 250

 

 
Denver, Colorado 80202   (303) 592-8075
(Address of principal executive offices)   (Registrant's telephone number, including area code)

         Securities pursuant to Section 12(b) of the Act:

Title of Each Class   Name of Exchange on Which Registered
Common Stock   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 the registrant's knowledge, in definitive proxy or information statements incorporated by reference on Part III of this Form 10-K or any amendment to this Form10-K. o

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

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

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

         At June 30, 2011, the aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $1,048,428,843. The number of shares of the registrant's Common Stock outstanding as of February 27, 2012, was 263,073,025.

DOCUMENTS INCORPORATED BY REFERENCE

         Certain portions of the registrant's definitive proxy statement to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than April 29, 2012, in connection with the registrant's 2011 Annual Meeting of Shareholders, are incorporated herein by reference into Part III of this Annual Report on Form 10-K.

   


Table of Contents

KODIAK OIL & GAS CORP.
FORM 10-K
TABLE OF CONTENTS

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

  1

PART I

  3

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

  3

ITEM 1A. RISK FACTORS

  21

ITEM 1B. UNRESOLVED STAFF COMMENTS

  40

ITEM 3. LEGAL PROCEEDINGS

  40

ITEM 4. MINE SAFETY DISCLOSURES

  40

PART II

  41

ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

  41

ITEM 6. SELECTED FINANCIAL DATA

  50

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

  51

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

  68

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  71

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

  110

ITEM 9A. CONTROLS AND PROCEDURES

  110

ITEM 9B. OTHER INFORMATION

  113

PART III

  114

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

  114

ITEM 11. EXECUTIVE COMPENSATION

  114

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

  114

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

  114

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

  114

PART IV

  115

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

  115

GLOSSARY OF CRUDE OIL AND NATURAL GAS TERMS

  121

SIGNATURES

  124

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        The information discussed in this annual report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 (the "Securities Act") and Section 21E of the Securities Exchange Act of 1934 (the "Exchange Act"). All statements, other than statements of historical facts, included herein concerning, among other things, planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled or completed after the date hereof, future cash flows and borrowings, pursuit of potential acquisition opportunities, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. These forward-looking statements are identified by their use of terms and phrases such as "may," "expect," "estimate," "project," "plan," "believe," "intend," "achievable," "anticipate," "will," "continue," "potential," "should," "could," and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties. Our results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including, among others:

    unsuccessful drilling and completion activities and the possibility of resulting write-downs;

    capital requirements and uncertainty of obtaining additional funding on terms acceptable to us;

    price volatility of oil and natural gas prices, and the effect that lower prices may have on our net income and stockholders' equity;

    a decline in oil or natural gas production or oil or natural gas prices, and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;

    geographical concentration of our operations;

    constraints imposed on our business and operations by our credit agreements and our ability to generate sufficient cash flows to repay our debt obligations;

    availability of borrowings under our credit agreements;

    termination fees related to drilling rig contracts and pressure pumping service contract;

    increases in the cost of drilling, completion and gas gathering or other costs of production and operations;

    our ability to successfully drill wells that produce oil or natural gas in commercially viable quantities;

    failure to meet our proposed drilling schedule;

    financial losses and reduced earnings related to our commodity derivative agreements, and failure to produce enough oil to satisfy our commodity derivative agreements;

    adverse variations from estimates of reserves, production, production prices and expenditure requirements, and our inability to replace our reserves through exploration and development activities;

    our current level of indebtedness and the effect of any increase in our level of indebtedness;

    hazardous, risky drilling operations and adverse weather and environmental conditions;

    limited control over non-operated properties;

    reliance on limited number of customers;

    title defects to our properties and inability to retain our leases;

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    incorrect estimates of proved reserves, the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs of properties that we acquire;

    our ability to successfully develop our large inventory of undeveloped operated and non-operated acreage;

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

    constraints in the Williston Basin with respect to gathering, transportation and processing facilities and marketing;

    federal, state and tribal regulations and laws;

    our current level of indebtedness and the effect of any increase in our level of indebtedness;

    risks in connection with potential acquisitions and the integration of significant acquisitions;

    price volatility of oil and natural gas prices, and the effect that lower prices may have on our net income and stockholders' equity;

    a decline in oil or natural gas production or oil or natural gas prices, and the impact of general economic conditions on the demand for oil and natural gas and the availability of capital;

    impact of environmental, health and safety, and other governmental regulations, and of current or pending legislation;

    federal and state legislation and regulatory initiatives relating to hydraulic fracturing;

    federal, state and tribal regulations and laws;

    integration of significant acquisitions, and difficulty managing our growth and the related demands on our resources;

    developments in the global economy;

    constraints imposed on our business and operations by our credit agreements and our Senior Notes and our ability to generate sufficient cash flows to repay our debt obligations;

    financing and interest rate exposure;

    effects of competition;

    effect of seasonal factors;

    lack of availability of drilling rigs, equipment, supplies, insurance, personnel and oil field services; and

    further sales or issuances of common stock.

        Finally, our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled "Risk Factors" included elsewhere in this annual report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this annual report. Other than as required under securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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PART I

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

Company Overview

        Kodiak Oil & Gas Corp. ("Kodiak," "we" or the "Company") is an independent energy company focused on the exploration, exploitation, acquisition and production of crude oil and natural gas in the United States. We have developed an oil and natural gas asset base of proved reserves, as well as a portfolio of development and exploratory drilling opportunities on high-potential prospects with an emphasis on oil resource plays. Our oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota. Kodiak's historic focus has been to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling.

        Since late 2010 and throughout 2011, we have added significantly to our asset base in the Williston Basin through targeted acquisitions of properties within our core operating area. We intend to continue to expand our asset base by evaluating and investing in acquisitions as well as drilling and completing wells within our current lands.

        As of January 31, 2012, we have approximately 169,000 net acres under lease including 157,000 net acres in the Bakken oil play in the Williston Basin of North Dakota and Montana. Included in this total is acreage from three significant acquisitions that closed in 2011 and early 2012, which collectively added approximately 88,000 net acres.

        As of the date of this filing, we operate six drilling rigs on our acreage, and we have a seventh operated rig under contract for delivery in the second quarter of 2012. In addition, our partner in an area of mutual interest is currently operating two rigs. We have an approximate 50% ownership interest in this area of mutual interest.

        As of the date of this filing, we operate, or have an interest in, a total of 137 gross (60.2 net) producing wells in the Williston Basin. This includes 35 gross (15.4 net) wells completed and turned to production in 2011 and 62 gross (25.0 net) wells acquired during 2011 and early 2012.

        Our capital expenditures budget for 2012 is $585.0 million which is expected to fund the drilling of 73 gross (51.0 net) wells, the installation of related midstream infrastructure and leasehold acquisitions needed to enhance our existing positions. Excluding the acquisitions, our net capital expenditures in 2011 totaled $260.6 million for the drilling of 24.6 net wells and completion of 15.5 net wells. We expect to fund our 2012 capital program through cash flows from operations, existing working capital and our borrowing capacity under our credit facility.

        The Company was incorporated on March 17, 1972 in the Province of British Columbia, Canada, under the name "Pacific Talc Ltd." pursuant to the Company Act (British Columbia). On November 12, 1998, the name of the Company was changed to "Columbia Copper Company Ltd." On September 28, 2001, the Company was continued from British Columbia to the Yukon Territory and the name of the Company was changed to "Kodiak Oil & Gas Corp." On September 23, 2003, we incorporated a wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. in Colorado. Kodiak Oil & Gas (USA) Inc. was formed to hold all of our US oil and gas properties located in the United States.

        For a summary of Kodiak's financial information, including revenues from external customers, information on net income and loss, long-lived assets, and total assets, see "Item 6. Selected Financial Data" and "Item 8. Financial Statements and Supplementary Data."

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Our Strategy

        Our business strategy is to create value for our stakeholders by growing reserves, production volumes and cash flow utilizing advanced development, drilling and completion technologies to systematically explore for, develop and produce oil and natural gas reserves, and evaluate strategic acquisitions. Key elements of our business strategy include:

        Focus on Developing our Williston Basin Leasehold Position.    We intend to continue developing our acreage position in the Williston Basin in order to enhance the value of its resource potential. Due to the results from our producing wells and current commodity prices, we intend to concentrate all of our 2012 capital expenditures in the Williston Basin. We believe that our experience in the application of advanced drilling and completion techniques, our access to drilling rigs, our pressure pumping services agreement and the high working interests that we maintain in our properties provide us with a competitive advantage in developing our approximately 157,000 net acres that are prospective for the Bakken.

        Leverage our Experience in the Williston Basin.    We continue to develop expertise in drilling and completion technologies in horizontal drilling and multi-stage isolated fracture stimulations. We continue to refine our drilling and completion techniques, as well as monitor the results of other operators, in an effort to enhance well performance and the associated estimated ultimate recoveries and rates of return.

        Retain Operational Control and Significant Working Interest.    We typically seek to maintain operational control of our development and drilling activities. As operator, we retain more control over the timing, selection and process of drilling prospects, and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of our capital expenditures. Retaining operational control also gives us the ability to control the financing, construction and operation of infrastructure related to our production operations.

        Evaluate Acquisitions in the Williston Basin.    We will continue to evaluate strategic acquisitions in the Williston Basin. Our focus on targeted opportunities in the Williston Basin allows us to maximize the efficiency of our drilling and exploration activities and further leverage our knowledge and experience. This focus has allowed us to capture economies of scale and obtain services timely in a highly competitive environment.

        Maintain Financial Flexibility.    Our goal is to remain financially strong, yet flexible, through the prudent management of our balance sheet and appropriate management of commodity price volatility. Our strategy to retain operational control provides for financial flexibility and allows us to manage the timing of a substantial portion of our capital expenditure program.

Our Competitive Strengths

        We believe we possess a range of competitive strengths, including:

        Substantial Leasehold Position in the Core of the Williston Basin.    As of January 31, 2012, we hold approximately 157,000 net leasehold acres in the Williston Basin. Our concentrated acreage position is prospective for the Bakken and Three Forks formations. We believe the results of our active drilling program and drilling activity by other exploration and production companies have significantly improved the risk profile of our concentrated acreage position. We expect that the scale and concentration of our acreage combined with our high operated working interest will also enable us to achieve operational efficiencies and improve our drilling and completion costs.

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        Oil-Weighted Production and Reserves and Increasing Collateral Value.    As of December 31, 2011, approximately 89% of our 51.7 MMBoe net proved reserves are comprised of oil, after giving effect to the significant oil and gas property acquisition we closed in January 2012. For a discussion of the January 2012 acquisition, please see the heading "2010, 2011 and Early 2012 Acquisitions" in Item 7 of this Annual Report. Additionally, we currently operate a six drilling rig program and have a seventh rig under contract for delivery in the second quarter of 2012. We plan to drill or participate in approximately 73 gross (51 net) wells in the Williston Basin in 2012.

        Large, Multi-Year Drilling Inventory Targeting Primarily Oil Production.    During 2011, we and other operators continued to evaluate well bore spacing in both the Middle Bakken and Three Forks. Based upon the early work that has been completed we believe we have a drilling inventory that will last approximately 8 - 10 years with our current rig count. As additional work is completed in both the Bakken and Three Forks, we anticipate that the number of drillable locations could increase.

        High Operatorship and Operational Scale.    As we have expanded our acreage holding we have maintained operatorship over the majority of our acreage. As a result, we have experienced increased operational scale, allowing us to secure a full-time 24-hour dedicated fracture stimulation ("frac") crew that commenced operations in early 2012. In addition, we recently added a second completion crew on an as-needed and if available basis. We believe the access to completion services provided by these frac crews, particularly from our dedicated frac crew, provides us with the operational scale that will enable us to realize cost efficiencies as we continue to develop our large acreage position. By operating our properties we retain the ability to adjust our capital expenditure program based on well economics and rates of return.

        Experienced Management and Technical Teams.    Our management and technical teams have an average of more than 25 years of industry experience, primarily in the Rocky Mountains and including work for larger exploration and production companies. The team is responsible for being an early mover in the acquisition of acreage in the Williston Basin and identifying the benefits of operational scale in the region. Our team also possesses substantial expertise in horizontal drilling and completions, including 53 gross (38.0 net) operated horizontal wells drilled to date.

Our Key Oil and Gas Property Acquisitions

        Commencing in late 2010 through early 2012, we closed several significant oil and gas property acquisitions through which we substantially expanded our presence in the Williston Basin. Pursuant to these acquisitions, we acquired interests in an aggregate of approximately 103,000 net acres of Williston Basin leaseholds, and related producing properties. In total, through these acquisitions, we acquired 66 gross (27.8 net) producing wells and 9 gross (5.8 net) wells that were awaiting completion. We paid aggregate consideration for these acquisitions of approximately $1.1 billion in cash and 7.6 million shares of our common stock. For details relating to each of these acquisitions, please see the discussion under the heading "2010, 2011 and Early-2012 Acquisitions" included in Item 7 of this Annual Report, which discussion is incorporated herein by reference.

Our Oil and Gas Reserves

        As of December 31, 2011, we had estimated proved reserves of 35.6 MMBbls of oil and 25.5 Bcf of natural gas with a present value discounted at 10% of $850.7 million based on pricing described below, before income tax effect, or $660.0 million after the effect of income taxes (Please refer to Item 7 under the heading PV-10 of this Annual Report for further discussion regarding the use of this Non-GAAP measure). This is an increase of 255% over our 2010 crude oil reserves and 185% over our 2010 natural gas reserves. Our reserves are comprised of 89% crude oil and 11% natural gas on an energy equivalent basis.

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        All of our reserves are located within the continental United States with 99.5% in the Williston Basin in North Dakota and Montana. Netherland Sewell & Associates, Inc. ("NSAI"), our independent petroleum engineering consulting firm, prepared our estimated reserves as of December 31, 2011, 2010 and 2009. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices, and other factors. You should read the notes following the table below and the information following the notes to our audited financial statements for the years ended December 31, 2011 and 2010 included in this Annual Report in conjunction with the following reserve estimates:

 
  As of December 31,  
 
  2011(2)   2010(3)  

Proved Developed Oil Reserves (MBbls)

    13,178.8     3,756.4  

Proved Undeveloped Oil Reserves (MBbls)

    22,396.7     6,254.0  
           

Total Proved Oil Reserves (MBbls)

    35,575.5     10,010.4  
           

Proved Developed Gas Reserves (MMcf)

    8,956.8     3,653.0  

Proved Undeveloped Gas Reserves (MMcf)

    16,582.4     5,307.2  
           

Total Proved Gas Reserves (MMcf)

    25,539.2     8,960.2  
           

Total Proved Oil Equivalents (MBOE)(1)

    39,832.1     11,503.8  

Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10%(4) (In thousands)

  $ 659,975   $ 154,568  

(1)
We converted MMcf to MBoe at a ratio of six Mcf to one barrel of oil.

(2)
The values for the 2011 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31, 2011 crude oil price of $95.99 per barrel (West Texas Intermediate price) and natural gas price of $3.94 per MMBtu (Questar Rocky Mountains price) or $4.17 per MMBtu (Northern Ventura price). All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2011 was $88.40 per barrel of oil and $5.50 per Mcf for natural gas.

(3)
The values for the 2010 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31, 2010 crude oil price of $79.40 per barrel (West Texas Intermediate price) and natural gas price of $3.92 per MMBtu (Questar Rocky Mountains price) or $4.39 per MMBtu (Northern Ventura price). All prices are then further adjusted for transportation, quality and basis differentials. The average resulting price used as of December 31, 2010 was $69.15 per barrel of oil and $5.07 per Mcf for natural gas.

(4)
The Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10%, is referred to as the "Standardized Measure." There is a $190.7 million tax effect in 2011 and a $6.6 million tax effect in 2010. See Supplemental Oil and Gas Reserve Information (Unaudited) following our audited financial statements for the years ended December 31, 2011 and 2010.

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        The table below summarizes our 2011 reserves by field, operating area and categorization as of December 31, 2011, along with the remaining estimated reserves:


2011 Proved Reserves by Field and Category

Proved Developed Reserves

 
  Gross Wells   Net Wells   Net Remaining Oil
(MBbls)
  Net Remaining Gas
(MMcf)
  Net Remaining
Oil Equivalent
(MBOE)
 

Bakken/Three Forks

                               

Dunn County

    38     18.8     7,220.9     4,321.2     7,941.1  

Smokey/Koala

    21     7.9     3,120.5     2,832.3     3,592.5  

Polar

    27     6.9     2,381.6     1,105.2     2,565.8  

Grizzly

    6     2.8     364.9     245.0     405.7  
                       

Total Bakken/Three Forks

    92     36.4     13,087.9     8,503.7     14,505.1  
                       

Other Fields

    11     3.1     91.0     453.3     166.5  
                       

Total Proved Developed

    103     39.5     13,178.9     8,957.0     14,671.6  
                       


Proved Undeveloped Reserves

Bakken/Three Forks

                               

Dunn County

    33     21.1     8,178.5     6,930.3     9,333.5  

Smokey/Koala

    24     19.9     8,231.7     5,355.7     9,124.3  

Polar

    32     14.0     5,342.2     4,013.8     6,011.2  

Grizzly

    4     2.1     644.3     282.7     691.4  
                       

Total Bakken/Three Forks

    93     57.1     22,396.7     16,582.5     25,160.4  

Other Fields

                     
                       

Total Proved Undeveloped

    93     57.1     22,396.7     16,582.5     25,160.4  
                       

Total Proved Reserves

    196     96.6     35,575.6     25,539.5     39,832.0  
                       

        The increase in our total proved reserves in 2011 is a result of our increased drilling and completion activity on Bakken properties and the acquisitions completed during the year. We drilled a total of 47 gross (24.6 net) wells and completed 36 gross (15.5) net wells incurring a net total of $260.6 million in capital expenditures for these operations. The 15.5 net completed wells include 11.5 net wells targeting the middle Bakken Formation and 3.9 net wells targeting the Three Forks Formation, all with longer laterals (over 5,000 feet). Included in the 47 gross wells drilled were 23 gross (6.4 net) wells drilled by third parties in which we have non-operated interests. In addition, we acquired 28 gross (7.6 net) producing wells through two significant property acquisitions during 2011. The increase in total proved reserves also includes net positive revisions to our December 31, 2010 previously estimated proved reserves. This is primarily a result of adjusting our decline curve estimates based on more extensive production history.

        Largely as a result of our escalated drilling program that evaluated both the Middle Bakken and Three Forks formations and our recent property acquisitions, we increased the number of proved undeveloped (PUD) locations from 27 (17.3 net) at year-end 2010 to 93 (57.1 net) at year-end 2011. These PUD locations offset our existing producing wells or are in drilling units that offset producing wells.

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        Our total PUD reserves as of December 31, 2011 were 25.2 MMBoe, which represents 63% of our total proved reserves as compared to 62% at December 31, 2010. At year-end 2010, PUD reserves were attributed to 27 gross locations. Of these 27 gross locations, seven gross wells were drilled, completed and placed on production in 2011 as a result of incurred expenditures of $41.7 million. These seven wells were attributed 1.7 MMBoe at year-end 2010 and at year-end 2011, the same seven wells were estimated to have 2.1 MMBoe of remaining oil and gas reserves. Two of the 2010 PUD locations were further expanded with one additional Three Forks Formation well drilled from each PUD location. Of the 20 remaining 2010 PUD locations, as of January 31, 2012, seven locations have been drilled but not completed, and eleven locations remain undrilled but are in various stages of preparation and permit acquisition and are expected to be drilled over the next year.

        On January 10, 2012, we closed on a significant oil and gas property acquisition, which added additional proved reserves. The table below summarizes the total proved reserves, as of December 31, 2011, associated with the properties we acquired in January 2012:

Reserve Category
  Gross Wells   Net Wells   Net Remaining Oil
(MBbls)
  Net Remaining Gas
(MMcf)
  Net Remaining
Oil Equivalent
(MBOE)
 

Proved Developed Reserves

    33     16.1     4,125.4     3,271.5     4,670.7  

Proved Undeveloped Reserves

    37     25.6     6,385.2     5,012.3     7,220.6  
                       

Total Proved Reserves

    70     41.7     10,510.6     8,283.8     11,891.3  
                       

        The table below summarizes our total proved reserves as reported at December 31, 2011, after giving effect to the total proved reserves associated with the properties we acquired in January 2012 (also stated as of December 31, 2011):

Reserve Category
  Gross Wells   Net Wells   Net Remaining Oil
(MBbls)
  Net Remaining Gas
(MMcf)
  Net Remaining
Oil Equivalent
(MBOE)
 

Proved Developed Reserves

    136     55.6     17,304.4     12,228.5     19,342.2  

Proved Undeveloped Reserves

    130     82.7     28,781.9     21,594.9     32,381.0  
                       

Total Combined Proved Reserves

    266     138.3     46,086.3     33,823.4     51,723.2  
                       

Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used

        Our year-end reserve report, as well as the reserve report relating to the oil and gas properties we acquired in January 2012, were prepared by NSAI based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geoscience and engineering data, and other information we provided to them. To ensure accuracy and completeness of the data prior to submission to NSAI, the information we provide is reviewed by the following persons with the following qualifications:

    Senior Reservoir Engineer, Wally O'Connell: Mr. O'Connell, a Registered Professional Engineer, is our reserves manager and has over 35 years of experience in the oil and gas industry in the areas of engineering and reserves management. He has worked for us since 2007 in the role of reserves manager. Prior to such time, he served as Exploitation Manager-Wattenberg Area for both Anadarko Petroleum Corporation from 2006 to 2007 and Kerr-McGee Rocky Mountain Corporation from 1998 to 2006. Prior to such time, he served in a variety of lead reservoir and petroleum engineering positions at various companies, including Questa Engineering Corporation, Whiting Petroleum Corporation and Nicor Exploration Company. He received a

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      Bachelor of Science in Petroleum Engineering from Montana College of Mineral Science and Technology in 1972.

    Executive Vice President of Operations, Russell Branting: Dr. Branting has served as our Operations Manager since June 2007. He has more than 20 years of experience focused throughout the Rocky Mountain region. He has served in various positions in petroleum engineering and operations with Western Gas Resources, Inc., Tesco Underbalanced Drilling Services, Chevron USA, Inc., and Snyder Oil Corporation. He was most recently the Rocky Mountain Drilling Engineering Manager for Anadarko Petroleum Corp., where he was responsible for managing all operations ongoing in the Greater Green River Business Unit, deep Powder River Basin Business Unit and Exploration team. Dr. Branting earned his Ph. D. in Petroleum Engineering from the University of Wyoming in 1993.

    Chief Operating Officer, James Catlin: Mr. Catlin has over 30 years of geologic experience, primarily in the Rocky Mountain region. He has served as a director of the Company since February 2001 and Chief Operating Officer since June 2006. Mr. Catlin was an owner of CP Resources LLC, an independent oil and natural gas company, from 1986 to 2001. Mr. Catlin was a founder of Deca Energy and served as its Vice-President from 1980 to 1986. He worked as a district geologist for Petroleum Inc. and Fuelco prior to such time. He received Bachelor of Arts and Masters degrees in Geology from the University of Northern Illinois in 1973.

    President and Chief Executive Officer, Lynn Peterson: Mr. Peterson has approximately 30 years of experience in the oil and gas industry. He has served as a director of the Company since November 2001 and President and Chief Executive Officer since July 2002. He was an owner of CP Resources, LLC, an independent oil and natural gas company, from 1986 to 2001. Mr. Peterson served as Treasurer of Deca Energy from 1981 to 1986. Mr. Peterson was employed by Ernst and Whinney as a certified public accountant prior to this time. He received a Bachelor of Science in Accounting from the University of Northern Colorado in 1975.

        The reserves estimates shown herein have been independently evaluated by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Dan Paul Smith and Mr. John Hattner. Mr. Smith has been practicing consulting petroleum engineering at NSAI since 1980. He is a Registered Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. John Hattner has been practicing consulting petroleum geology at NSAI since 1991. Mr. Hattner is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 19 years of experience in the estimation and evaluation of reserves. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary's College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

        A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance,

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advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

        For more information regarding our oil and gas reserves, please refer to Note 15—Supplemental Oil and Gas Information (Unaudited), under in Item 8 in this Annual Report.

Our Areas of Operation

Williston Basin—157,000 net acres

        The following map depicts our primary areas of operations within the Williston Basin:

GRAPHIC

        Our Williston Basin acreage is located primarily in Dunn, McKenzie and Williams Counties, of North Dakota. Our primary geologic target in the Williston Basin is the Bakken Pool. In the Bakken Pool, our primary objective is the dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,300-11,300 feet and the Three Forks Formation that is present immediately below the lower Bakken Shale. The Williston Basin also produces from many other formations including, but not limited to, the Mission Canyon, Nisku and Red River. We currently operate a six-rig drilling program in the Williston Basin and anticipate continued operation of these rigs throughout 2012. We have a seventh drilling rig under contract for delivery in the second quarter of 2012. In addition to our operated rigs, our joint venture partner on our Dunn County acreage is operating two drilling rigs on the lands it operates. We anticipate having a working interest of up to 50% in approximately half of the wells to be drilled by these two non-operated rigs.

        For the year 2012, our capital expenditure budget is comprised of $575.0 million for drilling, completion, and related infrastructure. All of the 73 gross wells budgeted for 2012 are expected to have longer horizontal laterals approaching 10,000 feet. In 2011, we drilled a total of 47 gross (24.6 net) wells and completed a total of 35 gross (15.4 net) wells in the Williston Basin, and incurred a net total of $260.6 million in capital expenditures.

        As discussed elsewhere, during 2011 and January 2012, we completed three significant acquisitions of oil and gas properties that significantly expanded our existing operating areas. The aggregate consideration paid in these three acquisitions totaled $972.4 million. The acquired assets, which are comprised of producing properties and undeveloped leasehold, together with equipment and facilities,

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working capital, other related permits, contracts, and other items, are located in McKenzie, Williams and Divide Counties of North Dakota. As a result of these acquisitions, we acquired leasehold of approximately 88,000 net acres, all of which we believe is prospective for Bakken and Three Forks production. Included in the acquisitions were a total of 62 gross (25.0 net) producing wells and 9 gross (5.8 net) wells awaiting completion operations.

        We have focused our operations in an area we believe has higher reservoir pressure, a high degree of thermal maturity, and is prospective for both the middle Bakken and the Three Forks formation. Based on recent drilling results, along with internal and third party reserve engineering analysis, we expect wells in this area to have economic ultimate recoveries ("EUR's") that range from 450 to over 900 MBOE. This area made up 98% of our total proved reserves as of December 31, 2011.

        Other important aspects of our drilling program in this core Williston Basin area include the following:

    Based upon our exploration efforts from 2009 thru 2011, we believe that the internal rate of return of the longer 10,000 foot laterals is higher than we were achieving with our shorter laterals of 5,000 feet or less. Although utilizing long laterals is more expensive, we estimate that the additional costs of drilling the longer lateral and adding more fracture stimulation stages is offset by the associated incremental increase in oil production.

    We have continued to drill on pads with two to four wells. We believe that, in future years, the number of wells drilled from each pad could increase. The significance of pad drilling is primarily directed to mobilization and demobilization of our drilling rigs which reduces costs and minimizes the impact on the surface locations. As the industry is facing a shortage of services, the use of pad drilling has become even more important as it lowers the number of moves required between wells, eliminating the need for trucks to move the equipment, a service that is in tight demand. Furthermore, we have seen efficiencies in our completion work as we eliminate mobilization and demobilization time for our pressure pumping company allowing it more efficient use of its time. In 2012, we plan to drill all wells from two-well to four-well pads.

    We expect to drill future wells with the density of approximately 1,300 feet or less of horizontal separation. We have completed five sets of middle Bakken wells with separation of approximately 1,300 feet or less. With the data obtained during the stimulation procedures, we experienced very little communication between formations and we believe that this spacing can be used as we move to development. Based upon the thickness of the middle Bakken in our prospect areas, we believe the results of our completion work support a density of up to four middle Bakken wells within many or our drilling units.

    Completion techniques have been and will continue to be evaluated with the expectation of further enhancing our completion methods as more data becomes available. Early results from our completion of seven gross operated wells in the Three Forks Formation are similar to the results of our middle Bakken wells and indicative of the potential of the formation. Results have shown very little communication with the middle Bakken reservoir, suggesting separate reservoirs. All of these wells were positioned less than 700 feet horizontally from a middle Bakken well with approximately 65 feet of vertical separation. This work has continued to support our belief that potentially three to four Three Forks wells can be completed in a drilling unit below the middle Bakken wells.

    Our leasehold is largely contiguous and by virtue of our high working interest and operatorship, we can control the development pace and location of surface facilities. We believe this strategy, combined with pad drilling and long laterals, will maximize the efficiency of our drilling program and minimize the infrastructure required to connect our wells to sales pipelines. As a result, we are able to plan our locations to minimize the number of wells required to hold our acreage by establishing production within the primary terms of our leases. Once all of our acreage is held

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      by production, we expect to gain efficiencies as this will allow us to develop acreage in a more methodical approach.

    Most of our core Williston Basin area is served by third party oil and gas gathering systems. The majority of our wells are connected to or are in the process of being connected to oil and gas pipelines. However, our gas sales continue to be limited by plant capacity needed to process the gas and strip out the high liquids content. Moving oil and gas through pipelines eliminates trucking costs and associated surface disturbance, and mitigates weather-related production interruptions. As the capacity of natural gas pipelines and related processing facilities increases, we should be able to capture additional revenue generated from the sale of associated natural gas that is currently flared.

    In Dunn County, we have progressed in connecting our wells to third party pipelines that transport water directly to disposal facilities. In 2012, we expect to drill water disposal wells on several of our producing areas outside of Dunn County and construct water gathering systems where appropriate.

Green River Basin—12,000 net acres

        Our primary leasehold in the Green River Basin is located in an area referred to as the Vermillion Basin. In this geologic region, we believe there is natural gas trapped in various sands, coals and shales at depths ranging from 2,000 feet to nearly 15,000 feet. The primary target of our current exploration efforts in this area is the over-pressured Baxter Shale at depths to approximately 13,000 feet. We will continue to monitor and evaluate this prospect before allocating further capital to this area.

Our Drilling Activity

        During 2011, we participated in drilling 47 gross (24.6 net) wells and we completed 36 gross (15.5 net) as producers. This compares to 22 gross (10.9 net) wells drilled and 16 gross (6.5 net) wells completed in 2010. Ten gross wells were waiting on completion at year-end 2011 and have either been scheduled for completion during early 2012 or are part of multi-well pads that are expected to be completed after all the wells have been drilled on each shared pad. Fifteen of the 36 gross wells completed in 2011 are Kodiak operated, all of which were completed with lateral lengths greater than 5,000 feet.

        All of our drilling activities are conducted on a contract basis by independent drilling contractors. We do not own any drilling equipment. The following table sets forth the number and type of wells that we completed during the years ended December 31, 2011, 2010 and 2009. In addition to these wells listed below, as of December 31, 2011, we have 25 gross (18.8 net) wells in progress, none of which were classified as such at December 31, 2010. Of these, 10 gross wells (6.7 net) were drilled and are awaiting completion.

 
  2011   2010   2009  
 
  Gross   Net   Gross   Net   Gross   Net  

Development wells, completed as:

                                     

Oil wells

    35     15.4     14     5.7          

Gas wells

    1     0.1                  

Non-Productive(1)

                         

Exploratory wells, completed as:

                                     

Oil wells

            2     0.8     9     4.8  

Gas wells

                         

Non-Productive(1)

                         
                           

Total

    36     15.5     16     6.5     9     4.8  
                           

(1)
A non-productive well (also known as a dry hole) is a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

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Productive Wells

        As part of our corporate strategy, we seek to operate our wells where possible and to maintain a high level of participation in our wells by investing our own capital in drilling operations. The following table summarizes our productive wells as of February 2012, all of which are located in the Rocky Mountain region of the United States. Productive wells are wells that are producing or capable of producing, including shut-in wells.

 
  Operated   Non-operated   Total  
 
  Gross   Net   Gross   Net   Gross   Net  

Williston Basin

                                     

Oil and associated gas wells

    75     50.6     62     9.6     137     60.2  

Wyoming/Colorado

                                     

Gas wells

            6     0.9     6     0.9  
                           

Total

    75     50.6     68     10.5     143     61.1  
                           

Our Leasehold

        As of January 31, 2012, we had several hundred lease agreements representing approximately 274,000 gross and 169,000 net acres in the Williston and Green River Basins. In the Williston Basin of North Dakota and Montana, as of January 31, 2012, we owned an interest in approximately 239,000 gross acres and 157,000 net acres.

        Our leasehold of approximately 34,000 net acres, in Dunn County, ND is entirely encompassed by the Fort Berthold Indian Reservation (FBIR) that is held in trust and administered by the Bureau of Indian Affairs (BIA) on behalf of the individual members of the Hidatsa, Mandan and Arikara tribes, collectively known as the Three Affiliated Tribes. Typically these lands are acquired through private negotiations with the individual land owners and the Three Affiliated Tribes and have a primary lease term of five years. In most cases we have one to three years remaining on the primary term of these leases. Approximately 30% of these lands are encompassed within federal operating units approved by the Bureau of Land Management ("BLM") that allow for the orderly exploration and development. The land owner typically retains an 18% landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre.

        The remainder of our Williston Basin leasehold, approximately 123,000 net acres, is held primarily on the basis of fee and federal leases. These leases typically carry a primary term of three to 10 years with landowner royalties of approximately 12.5% to 20.0%. In most cases we obtain "paid up" fee leases that do not require annual delay rentals. The federal lands require annual delay rentals of $1.50 to $2.00 per net acre.

        The majority of our acreage in Wyoming and Colorado is located on federal lands administered by BLM. Typically these lands are acquired through a public auction and have a primary lease term of ten years. The U.S. Department of the Interior normally retains a 12.5% royalty interest in these lands. Most of our lands in this area are encompassed within federal operating units approved by the BLM that allow for the orderly exploration and development of the federal lands. In most cases, these federal lands require an annual delay rental of $1.50 per net acre.

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        The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of January 31, 2012:

 
  Undeveloped Acreage(1)   Developed Acreage(2)   Total Acreage  
 
  Gross   Net   Gross   Net   Gross   Net  

Williston Basin

                                     

North Dakota

    127,099     110,101     105,120     42,743     232,219     152,844  

Montana

    3,148     1,790     3,240     2,446     6,388     4,236  

Green River Basin

                                     

Wyoming

    26,026     6,095     1,700     953     27,726     7,048  

Colorado

    7,339     4,960     0     0     7,339     4,960  
                           

Acreage Totals

    163,612     122,946     110,060     46,142     273,672     169,088  
                           

(1)
Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes proved reserves.

(2)
Developed acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.

        We believe we have satisfactory title, in all material respects, to substantially all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Substantially all of our proved oil and natural gas properties are pledged as collateral for borrowings under our credit facility.

        Substantially all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless (i) the existing lease is renewed; (ii) we have obtained production from the acreage subject to the lease prior to the end of the primary term, in which event the lease will remain in effect until the cessation of production; or (iii) it is contained within a Federal unit. Based on our current drilling plans we do not expect to lose any material acreage through expiration. The following table sets forth the gross and net acres of undeveloped land subject to leases that will expire during the next three years if oil and gas operations are not initiated, do not have options for renewal, or are not included in Federal units:

 
  Expiring Acreage  
Year Ending
  Gross   Net  

December 31, 2012

    26,621     14,699  

December 31, 2013

    24,443     16,294  

December 31, 2014

    24,421     13,430  
           

Total

    75,485     44,423  
           

Crude Oil and Natural Gas Market and Major Customers

        The principal products produced by us are crude oil and natural gas. These products are marketed and sold primarily to purchasers that have access to nearby pipeline facilities, refineries or other markets. Typically, both crude oil and natural gas are sold at the wellhead under contracts at negotiated prices based upon factors normally considered in the industry such as distance from well to pipeline, pressure, and quality. We currently have no long- term fixed-price physical delivery contracts in place.

        Commensurate with our growth in oil production, we have diversified our oil purchasers. The sales of our crude oil are to third-party marketing companies and a regional pipeline entity that also sells to

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these and other marketing companies. During the year ended December 31, 2011, we had sales to three purchasers that exceeded 10% of our total oil and gas revenue, whereby such purchasers purchased 27%, 25% and 11%, respectively, of our total oil and gas revenue. Although a substantial portion of our production is purchased by these customers, we do not believe the loss of any one customer would have a material adverse effect on our business as other customers would be accessible to us.

        Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The market for oil and natural gas is beyond our control and prices are difficult to predict. We currently use financial hedges to limit our overall exposure to fluctuations in oil prices but the hedging arrangements may also reduce our potential cash flows by limiting our exposure to commodity price increases. Our hedges are intended to mitigate the risk of a reduction in cash flows that may affect our ability to meet our obligations and capital expenditure budget while at the same time ensuring an acceptable rate of return on our investments. Our total volumes that can be hedged are limited under our credit facility to 85% to 90% of our forecasted production from our proved developed producing oil and gas reserves.

        Because we do not currently have firm capacity on pipelines or rail loading facilities that take oil and gas out of the Williston Basin, we will continue to be affected by changes in the price received locally versus prices at quoted market centers, including West Texas Intermediate (WTI). This differential can vary widely because of changes in supply and demand locally and at the market centers as well as the utilization of transportation capacity between these points. During 2011, we experienced differentials ranging from $4.00 per barrel to $13.50 per barrel. We are not currently able to hedge this differential using financial instruments, which reduces the effectiveness of our hedges that are based on WTI prices.

Competition

        The oil and gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise, and our financial resources. We must compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for drilling and completion of wells. As crude oil and natural gas prices decline, access to additional drilling equipment and completion services becomes more available. Conversely, as commodity prices increase, drilling equipment, may be in short supply from time to time.

Seasonality

        Winter weather conditions and lease stipulations can limit or temporarily halt our drilling and producing activities and other oil and natural gas operations. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operating and capital costs. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

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Governmental Regulations and Environmental Laws

Regulation of Oil and Gas Operations

        Our oil and natural gas exploration, production and related operations are subject to extensive laws and regulations promulgated by federal, state, tribal and local authorities and agencies. These laws and regulations often require permits for drilling operations, drilling bonds and reports concerning operations, and impose other requirements relating to the exploration for and production of oil and natural gas. Many of the laws and regulations govern the location of wells, the method of drilling and casing wells, the plugging and abandoning of wells, the restoration of properties upon which wells are drilled, temporary storage tank operations, air emissions from flaring, compression, the construction and use of access roads, sour gas management and the disposal of fluids used in connection with operations.

        Our operations are also subject to various conservation laws and regulations. These laws and regulations govern the size of drilling and spacing units or proration units, the density of wells that may be drilled in oil and natural gas properties and the unitization or pooling of oil and natural gas properties. In this regard, some states allow the forced pooling or integration of lands and leases to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose specified requirements regarding the ratability of production. On some occasions, tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities that must be addressed before those activities can proceed.

        The failure to comply with any such laws and regulations can result in substantial penalties. In addition, the effect of all these laws and regulations may limit the amount of oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Although we believe we are in substantial compliance with current applicable laws and regulations relating to our oil and gas operations, we are unable to predict the future cost or impact of complying with such laws and regulations because such laws and regulations are frequently amended or reinterpreted. The increasing regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability, which could have a material adverse effect on our business, financial condition and results of operations.

Environmental Regulation

        Our operations and properties are subject to extensive and changing federal, state, tribal and local laws and regulations relating to protection of the environment, wildlife protection, historic preservation, and health and safety. The recent trend in environmental legislation and regulation is generally toward stricter standards, and we expect that this trend will continue. Among other things, these laws and regulations:

    require the acquisition of permits or other authorizations before construction, drilling and certain other activities;

    require environmental reviews and assessments of proposed actions prior to the issuance of permits or the granting of governmental approvals;

    limit or prohibit construction, drilling and other activities on specified lands within wilderness and other protected areas; and

    impose substantial liabilities for pollution resulting from our operations.

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        The various environmental permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. We believe that we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

        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 may have a material adverse impact on our capital expenditures, results of operations or financial position.

        The Comprehensive Environmental, Response, Compensation, and Liability Act, or CERCLA, and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. It is not uncommon for the government to file claims requiring cleanup actions, demands for reimbursement for government-incurred cleanup costs, or natural resource damages, or for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance, as well as requirements for corrective actions. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum-related products. In addition, although RCRA classifies certain oil field wastes as "non-hazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. CERCLA, RCRA and comparable state statutes can impose liability for clean-up of sites and disposal of substances found on drilling and production sites long after operations on such sites have been completed. Other statutes relating to the storage and handling of pollutants include the Oil Pollution Act of 1990, or OPA, which requires certain owners and operators of facilities that store or otherwise handle oil to prepare and implement spill response plans relating to the potential discharge of oil into surface waters. The OPA, contains numerous requirements relating to prevention of, reporting of, and response to oil spills into waters of the United States. State laws mandate oil cleanup programs with respect to contaminated soil. A failure to comply with OPA's requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

        The Endangered Species Act, or ESA, seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, or destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. The ESA has been used to prevent or delay drilling activities and provides for criminal penalties for willful violations of its provisions. Other statutes that provide protection to animal and plant species and that may apply to our operations include, without limitation, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act, and the Bald and Golden Eagle Protection Act. Although we believe that our operations are in substantial compliance with these statutes, any change in these statutes or any reclassification of a species as threatened or endangered or re-determination of the extent of "critical habit" could subject us to significant expenses to modify our operations or could force us to discontinue some operations altogether.

        The National Environmental Policy Act, or NEPA, requires a thorough review of the environmental impacts of "major federal actions" and a determination of whether proposed actions on federal and certain Indian lands would result in "significant impact" on the environment. For purposes

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of NEPA, "major federal action" can be something as basic as issuance of a required permit. For oil and gas operations on federal and certain Indian lands or requiring federal permits, NEPA review can increase the time for obtaining approval and impose additional regulatory burdens on the natural gas and oil industry, thereby increasing our costs of doing business and our profitability.

        The Clean Water Act, or CWA, and comparable state statutes, impose restrictions and controls on the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the Environmental Protection Agency (EPA) or an analogous state agency. The CWA regulates storm water run-off from oil and natural gas facilities and requires a storm water discharge permit for certain activities. Such a permit requires the regulated facility to monitor and sample storm water run-off from its operations. The CWA and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges for oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.

        The Safe Drinking Water Act, or SDWA, and the Underground Injection Control (UIC) program promulgated thereunder, regulate the drilling and operation of subsurface injection wells. EPA directly administers the UIC program in some states and in others the responsibility for the program has been delegated to the state. The program requires that a permit be obtained before drilling a disposal well. Violation of these regulations and/or contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SWDA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

        Our operations employ hydraulic fracturing techniques to stimulate natural gas production from unconventional geological formations, which entails the injection of pressurized fracturing fluids into a well bore. The federal Energy Policy Act of 2005 amended the SDWA to exclude hydraulic fracturing from the definition of "underground injection" under certain circumstances. However, the repeal of this exclusion has been advocated by certain advocacy organizations and others in the public. Legislation to amend the SDWA to repeal this exemption and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, has been introduced in the current session of Congress. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA recently completing a study plan to examine the potential environmental impacts of hydraulic fracturing with a final report expected to be released in 2014. The U.S. Department of the Interior has announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. In addition, some states and localities have adopted, and others are considering adopting, regulations or ordinances that could restrict hydraulic fracturing in certain circumstances, or that would impose higher taxes, fees or royalties on natural gas production. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities, make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business. It is also possible that our drilling and injection operations could adversely affect the environment, which could result in a requirement to perform investigations or clean-ups or in the incurrence of other unexpected material costs or liabilities.

        The Clean Air Act, as amended, restricts the emission of air pollutants from many sources, including oil and gas operations. New facilities may be required to obtain permits before work can

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begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, more stringent regulations governing emissions of air pollutants, including greenhouse gases such as methane (a component of natural gas) and carbon dioxide are being developed by the federal government, and may increase the costs of compliance for some facilities or the cost of transportation or processing of produced oil and natural gas which may affect our operating costs. Legislation targeting air emissions from hydraulic fracturing activities has been introduced in the current session of Congress and if passed may increase our costs of compliance and doing business. In addition, the EPA has promulgated more stringent regulations governing emissions of toxic air pollutants from sources in the oil and gas industry, and these regulations may increase the costs of compliance for some facilities.

        Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many state governments have enacted legislation directed at controlling greenhouse gas emissions, and future state and federal legislation and regulation could impose additional restrictions or requirements in connection with our operations and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

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

        We are subject to federal and state laws and regulations relating to preservation and protection of historical and cultural resources. Such laws include the National Historic Preservation Act, the Native American Graves Protection and Repatriation Act, Archaeological Resources Protection Act, and the Paleontological Resources Preservation Act, and their state counterparts and similar statutes, which require certain assessments and mitigation activities if historical or cultural resources are impacted by our activities and provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements.

        We do not believe that our environmental, health and safety risks are materially different from those of comparable companies in the United States in the oil and natural gas industry. Nevertheless, there can be no assurance that such environmental, health and safety laws and regulations will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our capital expenditures, financial condition and results of operations.

        We have acquired, and may in the future acquire, interests in properties that have been operated in the past by others and may be liable for environmental damage, including historical contamination, caused by such former operators. Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

        We have not incurred, and do not currently anticipate incurring, any material capital expenditures for environmental control facilities.

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Employees and Office Space

        Our principal executive offices are located at 1625 Broadway, Suite 250, Denver, Colorado 80202, and our telephone number is (303) 592-8075. As of December 31, 2011, we employed 74 full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be very good.

Available Information

        We maintain a website at http://www.kodiakog.com. The information contained on or accessible through our website is not part of this Annual Report on Form 10-K. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to reports filed or furnished pursuant to Sections 13(a) and 15(d) of the Exchange Act, are available on our website, free of charge, as soon as reasonably practicable after we electronically file such reports with, or furnish those reports to, the SEC.

        We maintain a Code of Business Conduct and Ethics for Directors, Officers and Employees ("Code of Conduct"). A copy of our Code of Conduct may be found on our website in the Corporate Governance section. Our Code of Conduct contains information regarding whistleblower procedures.

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ITEM 1A.    RISK FACTORS

RISK FACTORS

        An investment in our common stock involves a high degree of risk. In addition to the other information included in this Annual Report on Form 10-K, you should carefully consider each of the risks described below before purchasing shares of our common stock. The risk factors set forth below are not the only risks that may affect our business. Our business could also be affected by additional risks not currently known to us or that we currently deem to be immaterial. If any of the following risks actually occur, our business, financial condition and results of operations could materially suffer. As a result, the trading price of our common stock could decline, and you may lose all or part of your investment.

Risks Related to Kodiak

Part of our strategy involves drilling in existing or emerging shale plays using available horizontal drilling and completion techniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

        Operations in the Bakken involve utilizing drilling and completion techniques as developed by ourselves and our service providers. Risks that we face while drilling include, but are not limited to, landing our wellbore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

        Our experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken is limited to the time since our operations beginning in 2008. 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 and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material writedowns of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Our current working capital, together with cash generated from anticipated production, may not be sufficient to support all planned exploration and development opportunities, our debt service obligation and our other contractual obligations.

        Our working capital, together with cash generated from anticipated production, may not be sufficient to support anticipated exploration and development opportunities, our debt service obligation and our other contractual obligations. If we realize lower than expected cash from production, either due to lower than anticipated production levels or a decline in commodity prices from recent levels, we may alter our drilling program, which may include reducing our rig count and sub-contracting our pressure pumping services agreement. Both of these may incur termination fees as discussed under the heading below "Contractual Obligations and Commitments" depending on the timing and contractual requirements of each contract. As we operate the majority of our acreage, we may have to adjust our drilling schedule to reflect the changing commodity price or oil field service environment. Under certain circumstances, we may conduct an offering of our securities, or reduce our ownership through

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joint ventures or asset sales. Should we reduce our ownership and relinquish the right to operate certain properties, we would become subject to obligations imposed by others, without the ability to control our drilling schedule. There can be no assurance that any such transactions can be completed or that such transactions would satisfy our operating capital requirements. Further, there can be no assurance that there will be credit available under our credit facility should we need it in the future. If we were not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned expenditures or restructure our operations, we would be unable to implement our original exploration and drilling program, and we may be unable to service our debt obligation or satisfy our contractual obligations. Any such consequences could have a material adverse effect on our business, financial condition and results of operation.

Substantially all of our producing properties and operations are located in the Williston Basin region, making us vulnerable to risks associated with operating in one major geographic area.

        As of December 31, 2011, approximately 99.5% of our estimated proved reserves and approximately 97% of our oil and natural gas sales volumes were generated in the Williston Basin in northwestern North Dakota and northeastern Montana. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

We may not be able to successfully drill wells that produce oil or natural gas in commercially viable quantities.

        We cannot assure you that each well we drill will produce commercial quantities of oil and natural gas. The total cost of drilling, completing and operating a well is uncertain before drilling commences. Overruns in budgeted expenditures are a common risk that can make a particular project uneconomical. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling each well whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. Our use of seismic data is subject to interpretation and may not accurately identify the presence of natural gas and oil. Further, many factors may curtail, delay or cancel drilling, including the following:

    delays and restrictions imposed by or resulting from compliance with regulatory requirements;

    changes in laws and regulations applicable to oil and natural gas activities;

    hazards resulting from unusual or unexpected geological or environmental conditions;

    shortages of or delays in obtaining equipment and qualified personnel;

    equipment failures or accidents;

    adverse weather conditions;

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    reductions in oil and natural gas prices;

    land title problems;

    lack of available gathering facilities or delays in construction of gathering facilities;

    unanticipated transportation costs and delays; and

    limitations in the market for oil and natural gas.

        Any of these risks can cause substantial losses, and some may entail personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. The occurrence of any of these events could negatively affect our ability to successfully drill wells that produce oil or natural gas in commercially viable quantities.

We may not adhere to our proposed drilling schedule.

        Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

    the availability and costs of drilling and service equipment and crews;

    economic and industry conditions;

    prevailing and anticipated prices for oil and gas;

    the availability of sufficient capital resources;

    the results of our exploitation efforts; and

    our ability to obtain permits for drilling locations.

        Although we have budgeted for 73 gross drilling locations for 2012, we may not be able to drill those locations within our expected time frame or at all. In addition, our drilling schedule may vary from our expectations because of future uncertainties.

Our commodity derivative arrangements could result in financial losses or could reduce our earnings.

        We enter into financial hedge arrangements (commodity derivative agreements) in order to manage our commodity price risk and to provide a more predictable cash flow from operations. We do not intend to designate our derivative instruments as hedges for accounting purposes. The fair value of our derivative instruments will be marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments will be recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments. We are currently limited by our credit facility to hedge up to 85% to 90% of our forecasted volumes from proved developed producing properties with collars, puts or fixed price instruments.

        Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative contracts for such period. If the actual amount of production is higher than we estimated, we will have greater commodity price exposure than we intended. If the actual amount of production is lower than the notional amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our hedging activities may not be as effective as we intend in

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reducing the volatility of our cash flows. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:

    production is less than the volume covered by the derivative instruments;

    the counter-party to the derivative instrument defaults on its contract obligations;

    there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

    the steps we take to monitor our derivative financial instruments do not detect and prevent transactions that are inconsistent with our risk management strategies.

        In addition, depending on the type of derivative arrangements we enter, the agreements could limit the benefit we would receive from increases in oil prices. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil prices.

We have historically incurred losses and cannot assure investors as to future profitability.

        Although we had net income in 2011, we have historically incurred losses from operations during our history in the oil and natural gas business. As of December 31, 2011, we had a cumulative deficit of approximately $104.4 million. Our ability to be profitable in the future will depend on successfully implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control. We cannot assure you that we will successfully implement our business plan or that we will achieve commercial profitability in the future. Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis.

The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, 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.

        This Annual Report contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that our initial rates of production of our wells will lead to greater overall production over the life of the wells, or that early results suggesting lack of reservoir continuity will prove to be accurate.

        You should not assume that the present value of future net revenues referred to in this Annual Report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the un-weighted average of the closing prices during the first day of each of the twelve months preceding the end of the fiscal year. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by oil or natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows.

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        The timing of both the production and the expenses from the development and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it reflect discount factors used in the market place for the purchase and sale of oil and natural gas.

Our reserves and production will decline, and unless we replace our oil and natural gas reserves, our business, financial condition and results of operations will be adversely affected.

        Producing oil and natural gas reserves ultimately results in declining production that will vary depending on reservoir characteristics and other factors. Thus, our future oil and natural gas production and resulting cash flow and earnings are directly dependent upon our success in developing our current reserves and finding additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

We have substantial indebtedness, and our level of indebtedness may increase, which could reduce our financial flexibility and increase the likelihood of default on our debt obligations.

        As of December 31, 2011, we had $650.0 million of outstanding indebtedness under our Senior Notes, $100.0 million of outstanding indebtedness under our second lien credit agreement and no outstanding indebtedness under our credit facility. On January 10, 2012, we repaid all of the outstanding indebtedness under our second lien credit agreement. In the future, we may incur additional indebtedness in order to make future acquisitions or to develop our properties. As of the date of this filing, we had up to $225.0 million of secured borrowing capacity available under our credit facility.

        Our level of indebtedness could affect our operations in several ways, including the following:

    a significant portion of our cash flows could be used to service our indebtedness;

    a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

    the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

    a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

    our debt covenants may affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

    a high level of debt may make it more likely that a reduction in the borrowing base of our credit facility following a periodic redetermination could require us to repay a portion of our then outstanding bank borrowings;

    a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; and

    we may be vulnerable to interest rate increases, as any borrowings under our credit facility will be at variable rates.

        Our 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

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factors affect our operations and our future performance. Many of these factors are beyond our control. If we do not have sufficient funds on hand to pay our debt, we may be required to seek a waiver or amendment from our lenders, refinance our indebtedness, incur additional indebtedness, sell assets or sell additional shares of securities. We may not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. 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. In addition, we may not be able to consummate an asset sale to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our credit agreements and the indenture governing our senior notes restrict our ability to use the proceeds from asset sales. Our failure to generate sufficient funds to pay our debts or to undertake any of these actions successfully could result in a default on our debt obligations, which would materially adversely affect our business, results of operations and financial condition.

Properties that we have acquired and that we may acquire in the future may not produce oil or natural gas as projected, and we may be unable to successfully determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.

        One of our growth strategies is to pursue selective acquisitions of undeveloped leasehold oil and natural gas reserves. When we choose to pursue an acquisition, we perform an informal review of the target properties that we believe is consistent with industry practices. However, these informal reviews are inherently incomplete. Generally, it is not feasible to review in depth every individual property involved in each acquisition, and we did not do so in connection with our recent acquisitions. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. We may not, and did not in connection with our recent acquisitions, perform an inspection on every well. Environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even if problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties, as was the case with respect to those properties acquired in our recent acquisitions.

Our business involves numerous operating hazards and exposure to significant weather and climate risks. We have not insured and cannot fully insure against all risks related to our operations, which could result in substantial claims for which we are underinsured or uninsured.

        We have not insured and cannot fully insure against all risks and have not attempted to insure fully against risks where the cost of available coverage is excessive relative to the perceived risks presented. In addition, certain pollution and environmental risks generally are not insurable. Our exploration, drilling and other activities are subject to risks such as:

    adverse weather conditions, natural disasters and other environmental disturbances;

    fires and explosions;

    environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

    abnormally pressured formations;

    mechanical failures of drilling equipment;

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    personal injuries and death, including insufficient worker compensation coverage for third-party contractors who provide drilling services; and

    acts of terrorism.

        In particular, our operations in North Dakota, Montana and Wyoming are conducted in areas subject to extreme weather conditions and often in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow and wet conditions. Unusually severe weather could further curtail these operations, including drilling of new wells or production from existing wells, and depending on the severity of the weather, could have a material adverse effect on our business, financial condition and results of operations. In addition, weather conditions and other events could temporarily impair our ability to transport our oil and natural gas production.

        We do not carry business interruption insurance coverage. Losses and liabilities arising from uninsured and underinsured events, which could arise from even one catastrophic accident, could reduce the funds available for our exploration, development and production activities and could materially and adversely affect our business, results of operations and financial condition.

We have limited control over activities in properties we do not operate, which could reduce our production and revenues, affect the timing and amounts of capital requirements and potentially result in a dilution of our respective ownership interest in the event we are unable to make any required capital contributions.

        We do not operate all of the properties in which we have an interest. As a result, we may have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. For all of the properties that are operated by others, we are dependent on their decision-making with respect to day-to-day operations over which we have little control. The failure of an operator of wells in which we have an interest to adequately perform operations, or an operator's breach of applicable agreements, could reduce production and revenues we receive from that well. The success and timing of our drilling and development activities on properties operated by others depend upon a number of factors outside of our control, including the timing and amount of capital expenditures, the available expertise and financial resources, the inclusion of other participants and the use of technology. Since we do not own a majority interest in many of the wells we do not operate, we may not be in a position to remove the operator in the event of poor performance.

        In particular, we are party to a joint venture agreement with a third party that relates to the development of certain of our properties in Dunn County, North Dakota. Pursuant to this agreement, we are required to pay 50% of the drilling expenses attributable to our joint venture's proportionate interest incurred in the area of mutual interest. We allocated $46.0 million of our 2012 capital budget toward the payment of these drilling expenses. If the expenses associated with our joint venture partner's exploration activity exceed our current expectations or if our joint venture partner mobilizes additional drilling rigs in the future, we may be required to make significantly higher capital contributions to satisfy our proportionate share of the exploration costs. If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations or we may have to reallocate our anticipated capital expenditure budget. In the event that we do not participate in future capital contributions with respect to this joint venture agreement or any other agreements relating to properties we do not operate, our respective ownership interest could be diluted.

We depend on a limited number of purchasers for sales of our oil. We are exposed to credit risk if one or more of our significant purchasers becomes insolvent and fails to pay amounts owed to us.

        For the year ended December 31, 2011, approximately 63% of our oil revenue was from three purchasers. It is possible that one or more of our customers will become financially distressed and default on their obligations to us. Furthermore, bankruptcy of one or more of our purchasers, or some

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other similar procedure, might make it difficult for us to collect all or a significant portion of amounts owed by the customers. Our inability to collect our accounts receivable could have a material adverse effect on our results of operations.

        The concentration of credit risk in a single industry affects our overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. Although we have not been directly affected, we are aware that some refiners have filed for bankruptcy protection, which has caused the affected producers to not receive payment for the production that was delivered. If economic conditions deteriorate, it is likely that additional, similar situations will occur which will expose us to added risk of not being paid for oil or natural gas that we deliver. We do not obtain credit protections such as letters of credit, guarantees or prepayments from our purchasers. We are unable to predict what impact the financial difficulties of any of our purchasers may have on our future results of operations and liquidity.

Our interests are held in the form of leases that we may be unable to retain and the title to our properties may be defective.

        Our properties are held under leases and working interests in leases. If we or the holder of a lease fails to meet the specific requirements of the lease regarding delay rental payments, continuous production or development, or similar terms, portions of the lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each lease will be met. The termination or expiration of our leases or the working interests relating to leases may reduce our opportunity to exploit a given prospect for oil and natural gas production and thus have a material adverse effect on our business, results of operation and financial condition.

        It is our practice in acquiring interests in oil and natural gas leases not to undergo the expense of retaining lawyers to fully examine the title to the interest to be placed under lease or already placed under lease. Rather, we rely upon the judgment of oil and natural gas lease brokers or landmen who actually do the field work in examining records in the appropriate governmental office before attempting to place under lease a specific interest. We believe that this practice is widely followed in the oil and natural gas industry.

        Prior to drilling a well for oil and natural gas, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to hire a lawyer to examine the title to the unit within which the proposed oil and natural gas well is to be drilled. Frequently, as a result of such examination, curative work must be done to correct deficiencies in the marketability of the title. The work entails expense and might include obtaining an affidavit of heirship or causing an estate to be administered. The examination made by the title lawyers may reveal that the oil and natural gas lease or leases are worthless, having been purchased in error from a person who is not the owner of the mineral interest desired. In such instances, the amount paid for such oil and natural gas lease or leases may be lost.

Our significant inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk.

        Our success is largely dependent upon our ability to develop our significant inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As of December 31, 2011, approximately 63% of our total proved reserves were undeveloped. To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves

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and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.

We depend on our key management personnel and technical experts and the loss any of these individuals could adversely affect our business.

        If we lose the services of our key management personnel, technical experts or are unable to attract additional qualified personnel, our business, financial condition, results of operations, development efforts and ability to grow could suffer. We have assembled a team of engineers and geologists who have considerable experience in applying advanced horizontal drilling and completion technology to explore for and to develop oil and natural gas. We depend upon the knowledge, skill and experience of these experts to assist us in improving the performance and reducing the risks associated with our participation in oil and natural gas exploration and development projects. In addition, the success of our business depends, to a significant extent, upon the abilities and continued efforts of our management.

The sale of our oil and natural gas production depends in part on gathering, transportation and processing facilities. Any limitation in the availability of, or our access to, those facilities would interfere with our ability to market the oil and natural gas that we produce and could adversely impact our drilling program, cash flows and results of operations.

        We deliver oil and natural gas through gathering, processing and pipeline systems that we do not own. The amount of oil and natural gas that we can produce and sell is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. In particular, natural gas produced in the Bakken has a high Btu content that requires gas processing to remove the natural gas liquids before it can be redelivered into transmission pipelines. Industry-wide in the Williston Basin, there is currently a shortage of gas gathering and processing capacity. Such shortage has limited our ability to sell our gas production. As a result, the majority of our gas from the Bakken wells to-date has been flared.

        The lack of availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing facilities, could result in our inability to realize the full economic potential of our production or in a reduction of the price offered for our production. Additionally, if we were prohibited from flaring natural gas due to environmental or other regulations, then we would be forced to shut-in producing wells, which would also adversely impact our drilling program. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities or any changes in regulatory requirements affecting flaring activities, could harm our business and, in turn, our financial condition, results of operations and cash flows.

Operations on the Fort Berthold Indian Reservation of the Three Affiliated Tribes in North Dakota are subject to various federal and tribal regulations and laws, any of which may increase our costs and delay our operations.

        Various federal agencies within the U.S. Department of the Interior, particularly the Office of Natural Resources Revenue (formerly the Minerals Management Service) and the Bureau of Indian Affairs, along with the Three Affiliated Tribes, promulgate and enforce regulations pertaining to operations on the Fort Berthold Indian Reservation. In addition, the Three Affiliated Tribes is a sovereign nation having the right to enforce laws and regulations independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees and other conditions that apply to lessees, operators and contractors conducting operations on Native American tribal lands. Lessees and operators conducting operations on tribal lands are generally subject to the Native American tribal court system. One or more of these factors may increase our costs of doing

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business on the Fort Berthold Indian Reservation and may have an adverse impact on our ability to effectively transport products within the Fort Berthold Indian Reservation or to conduct our operations on such lands.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

        We periodically evaluate potential acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of several factors, including:

    recoverable reserves;

    future oil and natural gas prices and their appropriate differentials;

    development and operating costs

    potential environmental and other liabilities; and

    our ability to obtain external financing to fund the purchase price.

        The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis, and, as is the case with certain liabilities associated with the properties acquired in our recent acquisitions, we are entitled to only limited indemnification for environmental liabilities.

        Significant acquisitions, including those described in this Annual Report, and other strategic transactions may involve other risks, including:

    diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

    challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

    challenge of attracting and retaining personnel associated with acquired operations; and

    failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

        The process of integrating operations, including those acquired in our recent acquisitions, could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

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We may have difficulty managing our growth and the related demands on our resources.

        We are experiencing significant growth through the expansion of our drilling program and through recent acquisitions. Our 2012 drilling program is the largest in our history. Our growth will place a significant strain on our financial, technical, operational and administrative resources. We may experience difficulties in finding and retaining additional qualified personnel. In an effort to meet the demands of our planned activities in 2012 and thereafter, we may be required to supplement our staff with contract and consulting personnel until we are able to hire new employees. In addition, our management may not be able to successfully or efficiently manage our growth, recent acquisitions and significant indebtedness. As a result, we may be unable to fully execute our growth plans, including acquiring or integrating new properties and drilling new and existing wells, all of which could have a material adverse effect on our growth and results of operations.

Our credit facility and the indenture governing our senior notes each contain operating and financial restrictions that may restrict our business and financing activities.

        Our credit facility and the indenture governing our senior notes each contain, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:

    make investments;

    incur additional indebtedness or issue preferred stock;

    create liens;

    sell assets;

    enter into agreements that restrict dividends or other payments by restricted subsidiaries;

    consolidate, merge or transfer all or substantially all of the assets of our company;

    engage in transactions with our affiliates;

    pay dividends or make other distributions on capital stock or prepay subordinated indebtedness; and

    create unrestricted subsidiaries.

        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 ability to comply with some of the covenants and restrictions contained in our credit facility and the indenture governing our senior notes may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired.

We are subject to financing and interest rate exposure risks.

        Our future success depends in part on our ability to access capital markets and obtain financing on reasonable terms. Our ability to access financial markets and obtain financing on commercially reasonable terms in the future is dependent on a number of factors, many of which we cannot control, including changes in:

    our credit rating;

    interest rates;

    the structured and commercial financial markets;

    market perceptions of us and the oil and natural gas exploration and production industry; and

    tax burdens due to new tax laws.

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        Any amounts due under our credit facility will bear interest at a variable rate. Any increases in our interest rates, or our inability to access the debt or equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations and growth prospects.

Risks Relating to Our Industry

Oil and natural gas prices are volatile. A substantial or extended decline in oil prices, an expansion in the differential between market prices and the price we receive and, to a lesser extent, a decrease in natural gas prices, could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

        Historically, the markets for natural gas and oil have been volatile and they are likely to continue to be volatile. As with most other companies involved in resource exploration and development, we may be adversely affected by future increases in the costs of conducting exploration, development and resource extraction that may not be fully offset by increases in the price received on sales of oil or natural gas. Our focus on exploration activities therefore exposes us to greater risks than are generally encountered in later-stage oil and natural gas property development companies.

        The economic success of any drilling project will depend on numerous factors, including:

    our ability to drill, complete and operate wells;

    our ability to estimate the volumes of recoverable reserves relating to individual projects;

    rates of future production;

    future commodity prices received; and

    investment and operating costs and possible environmental liabilities.

        Wide fluctuations in natural gas and oil prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and other factors that are beyond our control. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices a producer may expect and its level of production depend on numerous factors beyond its control, such as:

    worldwide and domestic supplies of natural gas and oil;

    weather conditions;

    the level of consumer demand;

    the price and availability of alternative fuels;

    technological advances affecting energy consumption;

    the proximity and capacity of natural gas pipelines and other transportation facilities;

    the price and level of foreign imports;

    domestic and foreign governmental regulations and taxes;

    the nature and extent of regulation relating to carbon dioxide and other greenhouse gas emissions;

    the actions of the Organization of Petroleum Exporting Countries;

    political instability or armed conflict in oil-producing regions; and

    overall domestic and global economic conditions.

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        Volatile oil and natural gas prices make it difficult to estimate the value of producing properties in an acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. Lower oil and natural gas prices may not only decrease revenues on a per unit basis, but also may reduce the amount of oil and natural gas that can be economically produced. Lower prices will also negatively affect the value of proved reserves.

        Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. A reduction in oil and gas prices may result in a decrease in the borrowing base or maximum credit available to us under our credit facility. In addition, we may need to record asset carrying value write-downs if prices fall, as was the case in 2008 and 2007.

        To attempt to reduce our price risk, we have implemented a strategy to hedge a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil would have a material adverse effect on our financial condition and results of operations and could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

Lower oil and natural gas prices may cause us to record ceiling test write-downs.

        We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a "full cost ceiling" which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders' equity. While we did not recognize any ceiling test write-downs for the year ended December 31, 2011, we may recognize write-downs in the future if commodity prices continue to decline or if we experience substantial downward adjustments to our estimated proved reserves.

Conducting operations in the oil and natural gas industry subjects us to complex laws and regulations that can have a material adverse effect on the cost, manner and feasibility of doing business.

        Companies that explore for and develop, produce and sell oil and natural gas in the United States are subject to extensive federal, state, local and tribal laws and regulations, including complex tax and environmental laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state, local and tribal agencies and authorities. Our ability to obtain, sustain and renew these permits on acceptable terms and without unfavorable restrictions or conditions is subject to a change in regulations and policies and to the discretion of the applicable governmental agencies or authorities, among other factors. Our inability to obtain, or our loss of or denial of extensions of, any of these permits could limit our ability to conduct our operations as planned. In addition, we may be required to make large expenditures to comply with governmental regulations.

        Matters subject to regulation include:

    water discharge and disposal permits for drilling operations;

    drilling permits and bonds;

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    method of drilling and casing wells;

    well stimulation processes;

    plugging and abandoning wells and reclamation and restoration of properties;

    reports concerning operations;

    air quality, noise levels and related permits;

    location and spacing of wells;

    rights-of-way and easements;

    unitization and pooling of properties;

    gathering, storage, transportation and marketing of oil and natural gas;

    habitat and endangered species protection;

    reclamation and remediation, and environmental protection;

    safety precautions;

    taxation; and

    waste transport and disposal permits and requirements.

        Failure to comply with these laws may result in the suspension or termination of operations and subject us to liabilities and administrative, civil and criminal penalties. Compliance costs can be significant. Moreover, these laws could change in ways that substantially increase the costs of doing business. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially and adversely affect our business, financial condition and results of operations.

Developments in the global financial system may have impacts on our liquidity and financial condition that we currently cannot predict.

        Global financial markets may have a material adverse impact on our business and our financial condition, and we may face challenges if conditions in the financial markets are inadequate to finance our activities at a reasonable cost of capital. There continues to be concerns over the worldwide economic outlook, geopolitical issues, the availability and costs of credit and the sovereign debt crisis have contributed to increased volatility in the global financial markets and commodity prices and diminished expectations for the global economy. We are unable to predict the duration or severity of the current economic situation or its impact on our business. As a result, our ability to access the capital markets or borrow money may be restricted or made more expensive at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or their failure to make required payments. Also, market conditions could have an impact on our natural gas and oil derivatives transactions if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, developments in the global financial system could lead to further reductions in the demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial situation cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

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

        Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state, local and tribal laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection, and historic preservation. These laws and regulations include, but are not limited to, the Clean Water Act, as amended by the Oil Pollution Act, the Clean Air Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation, and Liability Act, the Safe Drinking Water Act, the Endangered Species Act, the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act, the National Environmental Policy Act, the Occupational Safety and Health Act, the National Historic Preservation Act, the Native American Graves Protection and Repatriation Act, Archaeological Resources Protection Act, and the Paleontological Resources Preservation Act, and their state counterparts and similar statutes, which provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements. These laws and regulations may impose numerous obligations on us and our operations including by requiring us to obtain permits before conducting drilling or underground injection activities; restricting the types, quantities and concentration of materials that we can release into the environment; limiting or prohibiting drilling activities on certain lands lying within wilderness, wetlands and other protected areas, on lands containing protected species, or on lands containing historic, cultural, archeological or paleontological sites; subjecting us to specific health and safety requirements addressing worker protection; imposing substantial liabilities on us for pollution resulting from our operations; and requiring us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, and their interpretation and enforcement of these laws, regulations and permits have tended to become more stringent over time. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory, remedial or monitoring obligations; and the issuance of injunctions limiting or prohibiting some or all of our operations.

        There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations because of our handling of petroleum hydrocarbons and wastes; air emissions and wastewater discharges related to our operations; our ownership, lease or operation of real property, including acquired properties; and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of contamination at properties we currently own, lease or operate or have owned, leased or operated in the past. These laws often impose liability even if the owner, lessee or operator was not responsible for the contamination, or the contamination resulted from actions taken in compliance with all applicable laws in effect at the time. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may bring claims against us for property damage or personal injury, including as a result of exposure to hazardous materials, or to enforce compliance with, or seek damages under, applicable environmental laws and regulations. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and such changes could require us to make significant expenditures to attain and maintain compliance and 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.

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The regulations of "over-the-counter" derivatives introduced by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") could adversely impact our hedging strategy.

        Through its comprehensive new regulatory regime for derivatives, the Dodd-Frank Act imposes mandatory clearing, exchange-trading and margin requirements on many derivatives transactions (including formerly unregulated over-the-counter derivatives) in which we may engage. The Dodd-Frank Act also creates new categories of regulated market participants who will be subject to significant new capital, registration, recordkeeping, reporting, disclosure, business conduct and other regulatory requirements. While the Commodity Futures Trading Commission, or CFTC, and other federal agencies have adopted, and continue to adopt, numerous regulations pursuant to the Dodd-Frank Act, many of the key concepts and defined terms under the Dodd-Frank Act have not yet been delineated by rules and regulations to be adopted by the CFTC and other applicable regulatory agencies. As a consequence, it is difficult to predict the aggregate effect the Dodd-Frank Act and the regulations promulgated thereunder may have on our hedging activities.

        Whether and to what extent we will be subject to the rules and regulations promulgated under the Dodd-Frank Act will depend on the final rules and definitions adopted by the CFTC and other regulators. The possible effect of the Dodd-Frank Act could be to increase our overall costs of entering into derivatives transactions. In particular, new margin requirements, position limits and capital charges, even if not directly applicable to us, may cause an increase in the pricing of derivatives transactions sold by market participants to whom such requirements apply. Administrative costs, due to new requirements such as registration, recordkeeping, reporting, and compliance, even if not directly applicable to us, may also be reflected in higher pricing of derivatives. New exchange-trading and trade reporting requirements may lead to reductions in the liquidity of derivative transactions, causing higher pricing or reduced availability of derivatives, adversely affecting the performance of our hedging strategies. Additionally, the financial counterparties to our derivative instruments may be required to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Dodd-Frank Act could result in the cost of executing our hedging strategy increasing significantly, which could potentially result in an undesirable decrease in the amount of oil production we hedge. If our hedging costs increase and we are required to post cash collateral, our business would be adversely affected as a result of reduced cash flow and reduced liquidity. Additionally, in the event that we hedge lower quantities in response to higher hedging costs and increased margin requirements, our exposure to changes in commodity prices would increase, which could result in decreased cash flows.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into rock formations to fracture the surrounding rock and stimulate production. There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters, and the potential for impacts to surface water, groundwater, air quality and the environment generally. A number of lawsuits and enforcement actions have been initiated implicating hydraulic fracturing practices.

        Additional legislation or regulation could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

        Bills have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used in fracturing fluids by the oil and natural gas industry under the Safe Drinking Water Act (SDWA) and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community

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Right-to-Know Act, or other authority. In addition, bills have been introduced to regulate air emissions from hydraulic fracturing operations. Sponsors of such bills have asserted that air emissions from, and chemicals used in, the fracturing process could adversely affect drinking water supplies, surface waters, air quality and other natural resources, and threaten health and safety. The U.S. Environmental Protection Agency recently completed a study plan to examine the potential environmental impacts of hydraulic fracturing with initial results expected to be released in 2012 and a final report expected to be released in 2014, and the U.S. Department of the Interior has announced that it will consider regulations relating to the use of hydraulic fracturing techniques on public lands and disclosure of fracturing fluid constituents. Certain states have also considered or imposed reporting obligations relating to the use of hydraulic fracturing techniques.

        These proposals may lead to additional levels of regulation at the federal, state, tribal or local level that could cause operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Additional regulation could have the effect of prohibiting the use of hydraulic fracturing, which would prevent us from completing our wells and would have a material adverse effect on our operations and business.

        Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of crude oil and natural gas, including from the developing shale plays, and could make it more difficult to perform hydraulic fracturing. If these legislative and regulatory initiatives cause a material delay or decrease in our drilling and hydraulic fracturing activities, our business and profitability could be materially impacted.

Changes in tax laws may impair our results of operations.

        The Obama administration's proposed budget for the 2012 fiscal year includes numerous proposed tax changes. Among the changes contained in the budget proposal is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. These 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, (iv) the repeal of the exception to the passive loss exception limitation to the limitation for working interests in oil and gas properties, and (v) an extension increase of the amortization period for certain geological and geophysical expenditures, and (vi) the establishment of certain new fees. The Close Big Oil Tax Loopholes Act, which was introduced in the U.S. Senate in May 2011, includes many of the same proposals but is limited to taxpayers with annual gross revenues in excess of $100.0 million. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could adversely affect the amount of our taxable income or loss.

Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and gas.

        Studies over recent years have indicated that emissions of certain gases may be contributing to warming of the Earth's atmosphere. In response to these studies, governments have begun adopting domestic and international climate change regulations that require reporting and reductions of the emission of greenhouse gases. Methane, a primary component of natural gas, and carbon dioxide, a by-product of the burning of oil, natural gas and refined petroleum products, are considered greenhouse gases. In the United States, at the state level, many states, either individually or through multi-state regional initiatives, have begun implementing legal measures to reduce emissions of

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greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs or have begun considering adopting greenhouse gas regulatory programs. At the federal level, Congress has considered legislation that could establish a cap and trade system for restricting greenhouse gas emissions in the United States. The ultimate outcome of this federal legislative initiative remains uncertain.

        In addition to pending climate legislation, the EPA has issued greenhouse gas monitoring and reporting regulations. Beyond measuring and reporting, the EPA issued an "Endangerment Finding" under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations. The finding served as a first step to issuing regulations that require permits for and reductions in greenhouse gas emissions for certain facilities.

        Moreover, the EPA has begun regulating greenhouse gas emission from certain facilities pursuant to the Prevention of Significant Deterioration and Title V provisions of the Clean Air Act. In the courts, several decisions have been issued that may increase the risk of claims being filed by government entities and private parties against companies that have significant greenhouse gas emissions. Such cases may seek to challenge air emissions permits that greenhouse gas emitters apply for and seek to force emitters to reduce their emissions or seek damages for alleged climate change impacts to the environment, people, and property.

        Any existing or future laws or regulations that restrict or reduce emissions of greenhouse gases could require us to incur increased operating and compliance costs. In addition, such laws and regulations may adversely affect demand for the fossil fuels we produce, including by increasing the cost of combusting fossil fuels and by creating incentives for the use of alternative fuels and energy.

The oil and natural gas industry is subject to significant competition, which may adversely affect our ability to compete.

        Oil and natural gas exploration is intensely competitive and involves a high degree of risk. In our efforts to acquire oil and natural gas producing properties, we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also conduct refining and petroleum marketing operations on a worldwide basis. Their competitive advantages may negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital. Their competitive advantages may also better enable our competitors to sustain the impact of higher exploration and production costs, oil and natural gas price volatility, productivity variances among properties, competition from alternative fuel sources and technologies, overall industry cycles and other factors related to our industry.

Our operations and demand for our products are affected by seasonal factors, which may lead to fluctuations in our operating results.

        Our operating results are likely to vary due to seasonal factors. Demand for oil and natural gas products will generally increase during the winter because they are often used as heating fuels. The amount of such increased demand will depend to some extent upon the severity of winter. Because of the seasonality of our business and continuous fluctuations in the prices of our products, our operating results are likely to fluctuate from period to period.

The lack of availability or high cost of drilling rigs, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

        Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. Due to, among other things, our significant growth, we continue to experience a lack of resources and services. During these periods, the costs and delivery times of rigs,

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equipment and supplies tend to increase, in some cases substantially. In addition, the demand for, and wage rates of, qualified drilling rig crews rise as the number of active rigs in service increases within a geographic area. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. The lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel in the areas in which we operate could materially and adversely affect our business and results of operations.

Risks Relating to Our Common Stock

Future sales or other issuances of our common stock could depress the market for our common stock.

        We may seek to raise additional funds through one or more public offerings of our common stock, in amounts and at prices and terms determined at the time of the offering. Any sales of large quantities of our common stock could reduce the price of our common stock, and, to the extent that we raise additional capital by issuing equity securities, our existing stockholders' ownership will be diluted.

Our common stock has experienced price and volume volatility.

        The price of our common stock may be impacted by any of the following, some of which may have little or no relation to our company or industry:

    investor perception of our Company and the oil and natural gas industry, including industry trends;

    domestic and international economic and capital market conditions, including fluctuations in commodity prices;

    responses to quarter-to-quarter variations in our results of operations;

    announcements of significant acquisitions, strategic alliances, joint ventures or capital commitments by us or our competitors;

    additions or departures of key personnel;

    sales or purchases of our common stock by large stockholders or our insiders;

    accounting pronouncements or changes in accounting rules that affect our financial reporting; and

    changes in legal and regulatory compliance unrelated to our performance.

        In addition, the stock market in general and the market for natural gas and oil exploration companies in particular have experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating results or asset values of those companies. These broad market and industry factors may seriously impact the market price and trading volume of our common shares regardless of our actual operating performance.

We have not paid cash dividends on our common stock and do not anticipate paying any dividends on our common stock in the foreseeable future.

        We do not anticipate paying cash dividends on our common stock in the foreseeable future. Payment of future cash dividends, if any, will be at the discretion of our board of directors and will depend on our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors that our board of directors considers relevant. Furthermore, our credit agreements prohibit us from paying dividends with respect to our common stock. Accordingly, investors may only see a return on their investment if the value of our securities appreciates.

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Our constating documents permit us to issue an unlimited number of shares without shareholder approval.

        Our Articles of Continuation permit us to issue an unlimited number of shares of our common stock. Subject to the requirements of any exchange on which we may be listed, we will not be required to obtain the approval of shareholders for the issuance of additional shares of our common stock. Issuances of shares of our common stock will result in immediate dilution to existing shareholders and may have an adverse effect on the value of their shareholdings.

Sale, or the availability for sale, of substantial amounts of our common stock could adversely affect the value of our common stock.

        No prediction can be made as to the effect, if any, that future sales of our common stock, or the availability of common stock for future sales, will have on the market price of our common stock. We have several stockholders that hold a significant number of shares of our common stock. Sales of substantial amounts of our common stock in the public market and the availability of shares for future sale, including by one or more of our significant stockholders or shares of our common stock issuable upon exercise of outstanding options to acquire shares of our common stock, could adversely affect the prevailing market price of our common stock. This in turn would adversely affect the fair value of the common stock and could impair our future ability to raise capital through an offering of our equity securities.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

        Not applicable.

ITEM 3.    LEGAL PROCEEDINGS

        We have no material legal proceedings pending, and we do not know of any material proceedings contemplated by governmental authorities. There are no material proceedings to which any director, officer or any of our affiliates, any owner of record or beneficially of more than five percent of any class of our voting securities, or any associate of any such director, officer, our affiliates, or security holder, is a party adverse to us or our consolidated subsidiary or has a material interest adverse to us or our consolidated subsidiary.

ITEM 4.    MINE SAFETY DISCLOSURES

        These disclosures are not applicable to us.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON STOCK, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

        Shares of our common stock, no par value, are issued in registered form. The transfer agent for the shares is Computershare Trust Company Inc., 100 University Avenue, 9th Floor, Toronto, Ontario M5J 2Y1. Our common stock has been listed and posted for trading on the NYSE Amex LLC since June 21, 2006 through August 3, 2011 under the symbol "KOG". The Company made an application and received authorization from NYSE Regulation, Inc. to transfer the listing of its common stock from the NYSE Amex to NYSE. The Company began trading on the NYSE on August 4, 2011, under its current symbol "KOG". On February 27, 2012, there were 78 holders of record of our Common Stock which does not include the shareholders for whom shares are held in a nominee or street name.

 
  NYSE  
Quarter Ended
  High   Low  

December 31, 2011

  $ 9.95   $ 3.59  

September 30, 2011

  $ 7.03   $ 4.37  

June 30, 2011

  $ 7.44   $ 4.90  

March 31, 2011

  $ 7.70   $ 5.44  

December 31, 2010

  $ 6.95   $ 3.37  

September 30, 2010

  $ 3.63   $ 2.43  

June 30, 2010

  $ 4.34   $ 2.47  

March 31, 2010

  $ 3.45   $ 2.19  

Dividend Policy

        We have never paid any cash dividends on our common stock and do not anticipate paying any dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business. Any future determination to pay cash dividends will be at the discretion of our board of directors, and will be dependent upon our financial condition, results of operations, capital requirements, limitations under our credit facility and Senior Notes and other factors as our board may deem relevant at that time.

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Comparison of Cumulative Return

        The following graph compares the cumulative return on a $100 investment in our common stock over the last five fiscal years beginning January 1, 2007 through December 31, 2011, to that of the cumulative return on a $100 investment in the S&P 500 Composite, NYSE Arca Natural Gas, and the Dow Jones U.S. Oil & Gas Index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. The indices are included for comparative purpose only. This graph is not "soliciting material," is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing.

COMPARISON OF CUMULATIVE TOTAL RETURN

CHART

ASSUMES $100 INVESTED ON JAN. 1, 2007
ASSUMES DIVIDEND REINVESTED
FISCAL YEAR END DEC. 31, 2011

 
  12/31/06   12/31/07   12/31/08   12/31/09   12/31/10   12/31/11  

Kodiak Oil & Gas Corp. 

  $ 100   $ 56   $ 8   $ 57   $ 168   $ 242  

S&P 500 Composite

  $ 100   $ 105   $ 66   $ 84   $ 97   $ 99  

NYSE Arca Natural Gas

  $ 100   $ 131   $ 87   $ 128   $ 146   $ 156  

Dow Jones U.S. Oil & Gas

  $ 100   $ 135   $ 87   $ 102   $ 122   $ 127  

Exchange Controls

        Canada has no system of exchange controls. There are no exchange restrictions on borrowing from foreign countries nor on the remittance of dividends, interest, royalties and similar payments, management fees, loan repayments, settlement of trade debts, or the repatriation of capital. However, dividends remitted to U.S. Holders, as defined below, generally will be subject to Canadian withholding tax.

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        Except as provided in the Investment Canada Act (the "Act"), as amended by the Canada-United States Free Trade Implementation Act (Canada) and the Canada-United States Free Trade Agreement, there are no limitations specific to the rights of non-Canadians to hold or vote our common stock under the laws of Canada or the Yukon Territory or in our charter documents. Our company is not a "Canadian business," as defined in the Act; therefore, the limitations in the Act do not apply to our company.

Certain United States Federal Income Tax Considerations

        The following is a general summary of certain material U.S. federal income tax considerations applicable to a U.S. Holder (as defined below) arising from and relating to the acquisition, ownership, and disposition of common shares of the Company.

        This summary is for general information purposes only and does not purport to be a complete analysis or listing of all potential U.S. federal income tax considerations that may apply to a U.S. Holder arising from and relating to the acquisition, ownership, and disposition of common shares. In addition, this summary does not take into account the individual facts and circumstances of any particular U.S. Holder that may affect the U.S. federal income tax consequences to such U.S. Holder, including specific tax consequences to a U.S. Holder under an applicable tax treaty. Accordingly, this summary is not intended to be, and should not be construed as, legal or U.S. federal income tax advice with respect to any U.S. Holder. Each U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local tax, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

        No legal opinion from U.S. legal counsel or ruling from the Internal Revenue Service (the "IRS") has been requested, or will be obtained, regarding the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares. This summary is not binding on the IRS, and the IRS is not precluded from taking a position that is different from, and contrary to, the positions taken in this summary. In addition, because the authorities on which this summary is based are subject to various interpretations, the IRS and the U.S. courts could disagree with one or more of the positions taken in this summary.

Scope of this Summary

Authorities

        This summary is based on the Internal Revenue Code of 1986, as amended (the "Code"), Treasury Regulations (whether final, temporary, or proposed), published rulings of the IRS, published administrative positions of the IRS, U.S. court decisions, the Convention Between Canada and the United States of America with Respect to Taxes on Income and on Capital, signed September 26, 1980, as amended (the "Canada-U.S. Tax Convention"), and U.S. court decisions that are applicable and, in each case, as in effect and available, as of the date of this document. Any of the authorities on which this summary is based could be changed in a material and adverse manner at any time, and any such change could be applied on a retroactive or prospective basis which could affect the U.S. federal income tax considerations described in this summary. This summary does not discuss the potential effects, whether adverse or beneficial, of any proposed legislation that, if enacted, could be applied on a retroactive or prospective basis.

U.S. Holders

        For purposes of this summary, the term "U.S. Holder" means a beneficial owner of common shares that is for U.S. federal income tax purposes:

    an individual who is a citizen or resident of the U.S.;

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    a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) organized under the laws of the U.S., any state thereof or the District of Columbia;

    an estate whose income is subject to U.S. federal income taxation regardless of its source; or

    a trust that (1) is subject to the primary supervision of a court within the U.S. and the control of one or more U.S. persons for all substantial decisions or (2) has a valid election in effect under applicable Treasury regulations to be treated as a U.S. person.

Non-U.S. Holders

        For purposes of this summary, a "non-U.S. Holder" is a beneficial owner of common shares that is not a U.S. Holder. This summary does not address the U.S. federal income tax consequences to non-U.S. Holders arising from and relating to the acquisition, ownership, and disposition of common shares. Accordingly, a non-U.S. Holder should consult its own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local tax, and foreign tax consequences (including the potential application of and operation of any income tax treaties) relating to the acquisition, ownership, and disposition of common shares.

U.S. Holders Subject to Special U.S. Federal Income Tax Rules Not Addressed

        This summary does not address the U.S. federal income tax considerations applicable to U.S. Holders that are subject to special provisions under the Code, including the following U.S. Holders: (a) U.S. Holders that are tax-exempt organizations, qualified retirement plans, individual retirement accounts, or other tax-deferred accounts; (b) U.S. Holders that are financial institutions, underwriters, insurance companies, real estate investment trusts, or regulated investment companies; (c) U.S. Holders that are dealers in securities or currencies or U.S. Holders that are traders in securities that elect to apply a mark-to-market accounting method; (d) U.S. Holders that have a "functional currency" other than the U.S. dollar; (e) U.S. Holders that own common shares as part of a straddle, hedging transaction, conversion transaction, constructive sale, or other arrangement involving more than one position; (f) U.S. Holders that acquired common shares in connection with the exercise of employee stock options or otherwise as compensation for services; (g) U.S. Holders that hold common shares other than as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment purposes); (h) partnerships and other pass-through entities (and investors in such partnerships and entities); or (j) U.S. Holders that own or have owned (directly, indirectly, or by attribution) 10% or more of the total combined voting power of the outstanding shares of the Company. This summary also does not address the U.S. federal income tax considerations applicable to U.S. Holders who are (a) U.S. expatriates or former long-term residents of the U.S. subject to Section 877 of the Code, (b) persons that have been, are, or will be a resident or deemed to be a resident in Canada for purposes of the Tax Act; (c) persons that use or hold, will use or hold, or that are or will be deemed to use or hold common shares in connection with carrying on a business in Canada; (d) persons whose common shares constitute "taxable Canadian property" under the Tax Act; or (e) persons that have a permanent establishment in Canada for the purposes of the Canada-U.S. Tax Convention. U.S. Holders that are subject to special provisions under the Code, including U.S. Holders described immediately above, should consult their own tax advisor regarding the U.S. federal, U.S. federal alternative minimum, U.S. federal estate and gift, U.S. state and local tax, and foreign tax consequences relating to the acquisition, ownership and disposition of common shares.

        If an entity that is classified as a partnership for U.S. federal income tax purposes holds common shares, the U.S. federal income tax consequences to such partnership and the partners of such partnership generally will depend on the activities of the partnership and the status of such partners. Partners of entities that are classified as partnerships for U.S. federal income tax purposes should

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consult their own tax advisor regarding the U.S. federal income tax consequences arising from and relating to the acquisition, ownership, and disposition of common shares.

Tax Consequences Not Addressed

        This summary does not address the U.S. state and local, U.S. federal estate and gift, U.S. federal alternative minimum tax or foreign tax consequences to U.S. Holders of the acquisition, ownership, and disposition of common shares. Each U.S. Holder should consult its own tax advisor regarding the U.S. state and local, U.S. federal estate and gift, U.S. federal alternative minimum tax and foreign tax consequences of the acquisition, ownership, and disposition of common shares.

U.S. Federal Income Tax Consequences of the Acquisition, Ownership, and Disposition of Common Shares

        If the Company is not considered a "passive foreign investment company" (a "PFIC", as defined below) at any time during a U.S. Holder's holding period, the following sections will generally describe the U.S. federal income tax consequences to U.S. Holders of the acquisition, ownership, and disposition of the Company's common shares.

Distributions on Common Shares

        A U.S. Holder that receives a distribution, including a constructive distribution, with respect to the Company's common shares will be required to include the amount of such distribution in gross income as a dividend (without reduction for any applicable Canadian tax withheld from such distribution) to the extent of the current or accumulated "earnings and profits" of the Company. To the extent that a distribution exceeds the current and accumulated "earnings and profits" of the Company, such distribution will be treated (a) first, as a tax-free return of capital to the extent of a U.S. Holder's tax basis in the common shares and, (b) thereafter, as gain from the sale or exchange of such common shares (see "Disposition of Common Shares" below). However, the Company does not intend to maintain the calculations of earnings and profits in accordance with U.S. federal income tax principles, and each U.S. Holder should therefore assume that any distribution by the Company with respect to common shares will constitute ordinary dividend income. Dividends received on common shares generally will not be eligible for the "dividends received deduction."

        For taxable years beginning before January 1, 2013, a dividend paid by the Company generally will be taxed at the preferential tax rates applicable to long-term capital gains if (a) the Company is a "qualified foreign corporation" (as defined below), (b) the U.S. Holder receiving such dividend is an individual, estate, or trust, and (c) certain holding period requirements are met. The Company generally will be a "qualified foreign corporation" under Section 1(h)(11) of the Code (a "QFC") if (a) the Company is eligible for the benefits of the Canada-U.S. Tax Convention, or (b) common shares of the Company are readily tradable on an established securities market in the U.S. However, even if the Company satisfies one or more of such requirements, the Company will not be treated as a QFC if the Company is a PFIC for the taxable year during which the Company pays a dividend or for the preceding taxable year. (See the section below under the heading "Passive Foreign Investment Company Rules").

        If a U.S. Holder fails to qualify for the preferential tax rate applicable to dividends discussed above, a dividend paid by the Company to a U.S. Holder, including a U.S. Holder that is an individual, estate, or trust, generally will be taxed at ordinary income tax rates (and not at the preferential tax rates applicable to long-term capital gains). The dividend rules are complex, and each U.S. Holder should consult its own tax advisor regarding the dividend rules.

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Disposition of Common Shares

        A U.S. Holder will recognize a gain or loss on the sale or other taxable disposition of common shares in an amount equal to the difference, if any, between (a) the amount of cash plus the fair market value of any property received and (b) such U.S. Holder's tax basis in the common shares sold or otherwise disposed of. Subject to the PFIC rules discussed below, any such gain or loss generally will be capital gain or loss, which will be long-term capital gain or loss if common shares are held for more than one year.

        Preferential tax rates apply to long-term capital gains of a U.S. Holder that is an individual, estate, or trust. There are currently no preferential tax rates for long-term capital gains of a U.S. Holder that is a corporation. Deductions for capital losses are subject to significant limitations under the Code.

Receipt of Foreign Currency

        The amount of any distribution paid in foreign currency to a U.S. Holder in connection with the ownership of common shares, or on the sale, exchange or other taxable disposition of common shares, generally will be equal to the U.S. dollar value of such foreign currency based on the exchange rate applicable on the date of receipt (regardless of whether such foreign currency is converted into U.S. dollars at that time). A U.S. Holder that receives foreign currency and converts such foreign currency into U.S. dollars at a conversion rate other than the rate in effect on the date of receipt may have a foreign currency exchange gain or loss, which generally would be treated as U.S. source ordinary income or loss. If the foreign currency received is not converted into U.S. dollars on the date of receipt, a U.S. Holder will have a basis in the foreign currency equal to its U.S. dollar value on the date of receipt. Each U.S. Holder should consult its own U.S. tax advisor regarding the U.S. federal income tax consequences of receiving, owning, and disposing of foreign currency.

Foreign Tax Credit

        As described above under the heading "Exchange Controls," dividends paid to U.S. Holders generally will be subject to Canadian withholding tax. A U.S. Holder who pays (whether directly or through withholding) foreign income tax with respect to dividends paid on common shares generally will be entitled, at the election of such U.S. Holder, to receive either a deduction or a credit for such foreign income tax paid. Generally, a credit will reduce a U.S. Holder's U.S. federal income tax liability on a dollar-for-dollar basis, whereas a deduction will reduce a U.S. Holder's income subject to U.S. federal income tax. This election is made on a year-by-year basis and applies to all foreign taxes paid (whether directly or through withholding) by a U.S. Holder during a year.

        Complex limitations apply to the foreign tax credit, including the general limitation that the credit cannot exceed the proportionate share of a U.S. Holder's U.S. federal income tax liability that such U.S. Holder's "foreign source" taxable income bears to such U.S. Holder's worldwide taxable income. In applying this limitation, a U.S. Holder's various items of income and deduction must be classified, under complex rules, as either "foreign source" or "U.S. source." In addition, this limitation is calculated separately with respect to specific categories of income. Dividends paid by the Company generally will constitute "foreign source" income and generally will be categorized as "passive income." Gain or loss recognized by a U.S. Holder on the sale or other taxable disposition of common shares generally will be treated as "U.S. source" for purposes of applying the U.S. foreign tax credit rules unless the gain is subject to tax in Canada and is resourced as "foreign source" under the Canada-U.S. Tax Convention and such U.S. Holder elects to treat such gain or loss as "foreign source."

        The foreign tax credit rules are complex, and each U.S. Holder should consult its own tax advisor regarding the foreign tax credit rules.

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Additional Tax on Passive Income

        For tax years beginning after December 31, 2012, certain individuals, estates and trusts whose income exceeds certain thresholds will be required to pay a 3.8% Medicare surtax on "net investment income" including, among other things, dividends and net gain from disposition of property (other than property held in a trade or business). U.S. Holders should consult with their own tax advisors regarding the effect, if any, of this tax on their ownership and disposition of common shares.

Passive Foreign Investment Company Rules

        If the Company were to constitute a PFIC (as defined below) for any year during a U.S. Holder's holding period, then certain different and potentially adverse tax consequences would apply to such U.S. Holder's acquisition, ownership and disposition of common shares. The Company does not believe that it was a PFIC for the tax year ended December 31, 2011, and based on current business plans and financial projections, the Company does not expect that it will be a PFIC for the tax year ending December 31, 2012. The determination of whether the Company will be a PFIC for a taxable year depends, in part, on the application of complex U.S. federal income tax rules, which are subject to differing interpretations. In addition, whether the Company will be a PFIC for its current taxable year depends on the assets and income of the Company over the course of each such taxable year and, as a result, cannot be predicted with certainty as of the date of this document. Consequently, there can be no assurance regarding the Company's PFIC status for any taxable year during which U.S. Holders hold common shares, and there can be no assurance that the IRS will not challenge the determination made by the Company concerning its PFIC status.

        The Company generally will be a PFIC under Section 1297 of the Code if, for a taxable year, (a) 75% or more of the gross income of the Company for such taxable year is passive income or (b) 50% or more of the assets held by the Company either produce passive income or are held for the production of passive income, based on the quarterly average of the fair market value of such assets. "Gross income" generally includes all revenues less the cost of goods sold, plus income from investments and from incidental or outside operations or sources, and "passive income" includes, for example, dividends, interest, certain rents and royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions. Active business gains arising from the sale of commodities generally are excluded from passive income if substantially all of a foreign corporation's commodities are (a) stock in trade of such foreign corporation or other property of a kind which would properly be included in inventory of such foreign corporation, or property held by such foreign corporation primarily for sale to customers in the ordinary course of business, (b) property used in the trade or business of such foreign corporation that would be subject to the allowance for depreciation under Section 167 of the Code, or (c) supplies of a type regularly used or consumed by such foreign corporation in the ordinary course of its trade or business.

        In addition, for purposes of the PFIC income test and asset test described above, if the Company owns, directly or indirectly, 25% or more of the total value of the outstanding shares of another corporation, the Company will be treated as if it (a) held a proportionate share of the assets of such other corporation and (b) received directly a proportionate share of the income of such other corporation. In addition, for purposes of the PFIC income test and asset test described above, "passive income" does not include any interest, dividends, rents, or royalties that are received or accrued by the Company from a "related person" (as defined in Section 954(d)(3) of the Code), to the extent such items are properly allocable to the income of such related person that is not passive income.

        Under certain attribution rules, if the Company is a PFIC, U.S. Holders will be deemed to own their proportionate share of any subsidiary of the Company which is also a PFIC (a "Subsidiary PFIC"), and will be subject to U.S. federal income tax on (i) a distribution on the shares of a

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Subsidiary PFIC or (ii) a disposition of shares of a Subsidiary PFIC, both as if the holder directly held the shares of such Subsidiary PFIC.

        Under the default PFIC rules, a U.S. Holder would be required to treat any gain recognized upon a sale or disposition of our common shares as ordinary (rather than capital), and any resulting U.S. federal income tax may be increased by an interest charge which is not deductible by non-corporate U.S. Holders. Rules similar to those applicable to dispositions will generally apply to distributions in respect of our common shares which exceed a certain threshold level.

        While there are U.S. federal income tax elections that sometimes can be made to mitigate these adverse tax consequences (including, without limitation, the "QEF Election" and the "Mark-to-Market Election"), such elections are available in limited circumstances and must be made in a timely manner. U.S. Holders are urged to consult their own tax advisers regarding the potential application of the PFIC rules to the ownership and disposition of our common shares, and the availability of certain U.S. tax elections under the PFIC rules.

        U.S. Holders should be aware that, for each taxable year, if any, that the Company or any Subsidiary PFIC is a PFIC, the Company can provide no assurances that it will satisfy the record keeping requirements of a PFIC, or that it will make available to U.S. Holders the information such U.S. Holders require to make a QEF Election under Section 1295 of the Code with respect of the Company or any Subsidiary PFIC. Each U.S. Holder should consult its own tax advisor regarding the availability of, and procedure for making, a QEF Election with respect to the Company and any Subsidiary PFIC.

        The above discussion is only a brief summary of the PFIC rules. The PFIC rules are complex, and each U.S. Holder should consult its own financial advisor, legal counsel, or accountant regarding the PFIC rules and how the PFIC rules may affect the U.S. federal income tax consequences of the acquisition, ownership, and disposition of common shares.

Information Reporting; Backup Withholding Tax

        Under U.S. federal income tax law and Treasury Regulations, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. For example, U.S. return disclosure obligations (and related penalties) are imposed on individuals who are U.S. Holders that hold certain specified foreign financial assets in excess of $50,000. The definition of specified foreign financial assets includes not only financial accounts maintained in foreign financial institutions, but also, unless held in accounts maintained by a financial institution, any stock or security issued by a non-U.S. person, any financial instrument or contract held for investment that has an issuer or counterparty other than a U.S. person and any interest in a foreign entity. U. S. Holders may be subject to these reporting requirements unless their common shares are held in an account at a domestic financial institution. Penalties for failure to file certain of these information returns are substantial. U.S. Holders should consult with their own tax advisors regarding the requirements of filing information returns under these rules, including the requirement to file an IRS Form 8938 for prior tax years in which the obligation to file such form was suspended.

        Payments made within the U.S. or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from the sale or other taxable disposition of, common shares will generally be subject to information reporting and backup withholding tax, at the rate of 28% (increasing to 31% for payments made after December 31, 2012), if a U.S. Holder (a) fails to furnish such U.S. Holder's correct U.S. taxpayer identification number (generally on Form W-9), (b) furnishes an incorrect U.S. taxpayer identification number, (c) is notified by the IRS that such U.S. Holder has previously failed to properly report items subject to backup withholding tax, or (d) fails to certify, under penalty of perjury, that such U.S. Holder has furnished its correct U.S. taxpayer identification number and that the IRS has not notified such U.S. Holder that it is subject to backup withholding tax. However, certain exempt

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persons generally are excluded from these information reporting and backup withholding rules. Backup withholding is not an additional tax. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a credit against a U.S. Holder's U.S. federal income tax liability, if any, or will be refunded, if such U.S. Holder furnishes required information to the IRS in a timely manner. Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding rules.

Issuer Purchases of Equity Securities

        During the fiscal year ended December 31, 2011, neither the Company nor any affiliated purchaser purchased any of the Company's equity securities.

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ITEM 6.    SELECTED FINANCIAL DATA

        The following table sets forth selected consolidated financial data as of and for the years ended December 31, 2011, 2010, 2009, 2008 and 2007. The data as of and for the fiscal years ended December 31 for the respective years was derived from our historical consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K and in our prior Annual Reports on Form 10-K, as applicable.

        The following selected consolidated financial information should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Conditions and Results of Operations" and the consolidated financial statements and the notes thereto included in "Item 8. Financial Statements and Supplementary Data" presented elsewhere in this Annual Report on Form 10-K. Also see "Recently Adopted Accounting Pronouncements" included in the notes to the consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

 
  For the Years Ended December 31,  
 
  2011   2010   2009   2008   2007  
 
  (In thousands, except per share data)
 

Consolidated Statements of Income Information:

                               

Revenues:

                               

Oil sales

  $ 115,692   $ 30,212   $ 10,652   $ 5,397   $ 6,764  

Gas sales

    4,294     783     625     1,372     1,053  
                       

Total revenues

    119,986     30,995     11,277     6,769     7,817  
                       

Operating expenses:

                               

Oil and gas production

    26,885     6,795     2,220     3,579     1,758  

Depletion, depreciation, amortization and accretion

    32,068     8,234     3,159     4,172     5,206  

Asset impairment

                47,500     34,000  

General and administrative

    19,495     12,190     8,522     8,212     6,542  
                       

Total operating expenses

    78,448     27,219     13,901     63,463     47,506  
                       

Operating income (loss)

   
41,538
   
3,776
   
(2,624

)
 
(56,694

)
 
(39,689

)

Other income (expense):

                               

Loss on commodity price risk management activities

    (20,114 )   (6,146 )            

Interest income (expense), net

    (18,887 )   (39 )   53     196     1,503  

Other income

    1,338     7     8          
                       

Total other income (expense)

    (37,663 )   (6,178 )   61     196     1,503  
                       

Net income (loss)

  $ 3,875   $ (2,402 ) $ (2,563 ) $ (56,498 ) $ (38,186 )
                       

Net income (loss) per share:

                               

Basic

  $ 0.02   $ (0.02 ) $ (0.02 ) $ (0.62 ) $ (0.44 )
                       

Diluted

  $ 0.02   $ (0.02 ) $ (0.02 ) $ (0.62 ) $ (0.44 )
                       

Other Financial Information:

                               

Net cash provided by operating activities

  $ 53,913   $ 10,315   $ 9,396   $ (2,174 ) $ 2,073  

Net cash used in investing activities

  $ (590,749 ) $ (200,009 ) $ (28,155 ) $ (20,911 ) $ (47,910 )

Net cash provided by financing activities

  $ 517,242   $ 266,007   $ 36,064   $ 17,651   $ 382  

Consolidated Balance Sheet Information:

                               

Total assets

  $ 1,699,477   $ 369,937   $ 79,683   $ 39,016   $ 74,331  

Long-term debt

  $ 750,000   $ 40,000   $   $   $  

Total stockholders' equity

  $ 839,680   $ 299,047   $ 69,928   $ 32,998   $ 68,293  

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

        The following discussion and analysis should be read in conjunction with the "Selected Consolidated Financial Information" in Item 6 above and our historical consolidated financial statements and the accompanying notes included elsewhere in this Annual Report on Form 10-K.

Overview

        We are an independent energy company focused on the exploration, exploitation, acquisition and production of natural gas and crude oil in the United States. Our oil and natural gas reserves and operations are primarily concentrated in the Williston Basin of North Dakota. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas asset base of proved reserves, as well as a portfolio of development and exploratory drilling opportunities on high potential oil and natural gas prospects that we have the opportunity to explore, drill and develop. We will continue to evaluate and invest in acquisitions and internally generated prospects to increase the value of the Company.

2010, 2011 and Early 2012 Acquisitions

January 2012 Acquisition

        On January 10, 2012, we acquired certain oil and gas leaseholds, overriding royalty interests and producing properties located in North Dakota, and various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the "January 2012 Acquisition"). The effective date for this acquisition was September 1, 2011. This acquisition contributed no revenue to us for the year-ended December 31, 2011, nor were the oil and gas reserves included in our year-end reserve estimates.

        We closed this acquisition for aggregate consideration of approximately $638.2 million. This consideration was comprised of (i) 5,055,612 shares of the Company's common stock and (ii) cash consideration in an amount equal to approximately $588.4 million. The purchase price included $48.4 million in closing adjustments to reflect the effective date of the acquisition, which includes reimbursement to the seller in this transaction for operational expenditures during the interim period. We funded the cash balance due at closing through the release from escrow of the proceeds from our November 2011 high yield debt offering.

        Through this acquisition, we acquired approximately 50,000 net leasehold acres and net production of approximately 3,600 barrels of oil equivalent per day located primarily in McKenzie and Williams Counties, N.D. We will operate substantially all of the leasehold acquired.

October 2011 Acquisition

        On October 28, 2011, we acquired interests in approximately 13,400 net acres of Williston Basin leaseholds, and related producing properties located primarily in Williams County, North Dakota along with various other related rights, permits, contracts, equipment and other assets. The seller in this transaction received cash consideration of approximately $248.2 million, including certain purchase price adjustments calculated at the closing date. The effective date for the acquisition was August 1, 2011.

June 2011 Acquisition

        On June 30, 2011, we acquired interests in approximately 25,000 net acres of Williston Basin leaseholds and related producing properties located in McKenzie County, North Dakota along with

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various other related rights, permits, contracts, equipment and other assets for a combination of cash and stock. The seller in this transaction received 2,500,000 shares of the Company's common stock valued at approximately $14.0 million and cash consideration of approximately $71.5 million. The effective date for the acquisition was April 1, 2011.

November 2010 Acquisition

        On November 30, 2010, we acquired interests in approximately 14,500 net acres of Williston Basin leaseholds and related producing properties primarily located in McKenzie County, North Dakota for cash consideration of approximately $108.6 million. The effective date for the acquisition was August 1, 2011.

2012 Capital Budget

        Our board of directors approved a $585.0 million capital expenditure budget for 2012, all of which is allocated to oil and gas activities in the Williston Basin of North Dakota. We have allocated $550 million to the drilling of 73 gross (51 net) wells and $25.0 million for infrastructure build-out. Such infrastructure costs will primarily include expenses associated with connecting our wells to gathering systems for which we have contracted with third party pipeline companies. The remaining $10.0 million is allocated to our land leasing activities as we further increase our interests in our existing lands. We anticipate funding this capital program through a combination of existing working capital, an expected increase in our operating cash flows, and additional credit that should be available under our credit facility.

        Our 2012 capital expenditure budget is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results. While we continue to explore opportunities to expand our acreage position, our current budget is primarily allocated to drilling and completing wells. Additional leasehold acquisitions that we choose to pursue would require us to adjust our budget, as we have not allocated a significant portion of our 2012 capital budget to acreage acquisitions.

        Because of our predominantly contiguous leasehold, Kodiak's working interest averages approximately 66% in the operated 2012 drilling program, thereby providing flexibility within the budget in identifying suitable well locations and in the timing and size of capital investment. We anticipate increasing our current six-rig program to seven operated rigs during 2012 and we believe our permitting procedures will provide us with ample permits as we move through the year.

        Other factors that could cause us to further adjust our capital expenditure budget include increases or decreases in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, changes in commodity prices or well performance that differ from our forecasts, any of which could affect our operating cash flow.

        The following table sets forth our capital expenditures for the year ended December 31, 2011 and our capital expenditures budget for our principal properties in 2012. Capital expenditures include cash

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expenditures, accrued expenditures, oil and gas property acquisitions through the issuance of common stock and are net of divestitures.

 
  For the Years Ended December 31,  
 
  2012 Budget   2011 Actual   2010 Actual   2009 Actual  

Costs incurred:

                         

Acquisitions(1)

                         

Proved oil and gas properties

  $ 318,000   $ 152,500   $ 32,200   $  

Unproved oil and gas properties

    311,000     168,000     77,200      

Asset retirement obligations

    800     300     200      
                   

Total acquisitions

    629,800     320,800     109,600      
                   

Capital Expenditures

                         

Exploration and development costs

    575,000     260,600     66,800     26,700  

Unproved oil and gas properties

    10,000     14,900     18,500     500  

Asset retirement obligations

        1,300     600     200  

Capitalized interest

        8,400     500      
                   

Total capital expenditures

    585,000     285,200     86,400     27,400  
                   

Total costs incurred

  $ 1,214,800   $ 606,000   $ 196,000   $ 27,400  
                   

(1)
Includes acquisitions accounted for as business combinations.

Liquidity and Capital Resources

        The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2011, 2010 and 2009:

 
  For the Years Ended December 31,  
 
  2011   2010   2009  
 
  (In thousands)
 

Capital Resources and Liquidity

                   

Cash and cash equivalents at end of the period

  $ 81,604   $ 101,198   $ 24,885  

Cash held in escrow—current

  $ 12,194   $   $  

Net cash provided by operating activities

 
$

53,913
 
$

10,315
 
$

9,395
 

Net cash used in investing activities

  $ (590,749 ) $ (200,009 ) $ (28,155 )

Net cash provided by financing activities

  $ 517,242   $ 266,007   $ 36,064  

Increase (decrease) in cash and cash equivalents

  $ (19,594 ) $ 76,313   $ 17,304  

        Historically, our primary cash requirements have been for the exploration, development and acquisition of oil and gas properties, which we have financed through the proceeds of offerings of our equity and debt securities, borrowings under lending arrangements with financial institutions and, cash generated from operations. The aggregate consideration (including both cash consideration and equity consideration) for our three significant oil and gas property acquisitions during 2011 (each of which are discussed above under the heading "2010, 2011 and Early 2012 Acquisitions") was approximately $972.4 million. Additionally, during 2011, we incurred approximately $275.5 million in drilling and completion costs and additional leasehold acquisition costs. The total of the aforementioned acquisitions and our 2011 capital expenditures was approximately $1.25 billion (including both cash

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payments and equity issuances). In order to fund these expenditures, we undertook the following financing arrangements:

    We conducted equity financing through the sale of our common stock in July and November 2011 resulting in net cash proceeds of approximately $515.3 million, after deducting underwriting discounts and commissions and our offering expenses. As part of these equity offerings we issued a total of 75.9 million shares of common stock through public offerings. For further details on these transactions please refer to Note 10—Common Stock under Item 8 in this Annual Report.

    As part of the consideration given to close our oil and gas property acquisitions during 2011 and early 2012 , we issued approximately 7.6 million shares of our common stock valued at approximately $63.8 million.

    On November 23, 2011, we issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019 (the "Senior Notes"). The net proceeds were primarily used to finance our January 2012 property acquisition and repay all borrowings under our second lien credit agreement. For a discussion of the terms of these notes, please see the discussion below under the heading "Senior Notes".

    We utilized funds available from our credit facility and the second lien credit agreement to fund a portion of our property acquisitions during 2011. As a result of the November 2011 equity financing, through the sale of our common stock and Senior Notes offering, all outstanding balances were paid in full and as of the date of this filing remained unused. As noted above, the second lien credit agreement was terminated in January 2012, and as of the date of this filing, we have no balance outstanding under our credit facility.

        Our 2012 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We anticipate funding this capital program and meet our debt service requirements through a combination of existing working capital, the increase in our operating cash flows, and additional credit that may be available through our borrowing base facility. We plan to finance our 2012 capital expenditure budget of $585.0 million utilizing the following sources of capital:

        Cash flow from operations and existing working capital.    As of December 31, 2011, we had working capital of $72.8 million. Our working capital as of December 31, 2011 included, among other items, $81.6 million of cash and cash equivalents, $12.2 million of cash held in escrow and $22.1 million of prepaid tubular goods to be used in our 2012 drilling program.

        Our net cash provided by operating activities for the year ended 2011 was approximately $53.9 million as compared to $10.3 million for the same period in 2010. This increase is directly related to our successful drilling and completion operations as we have developed our Bakken properties and the addition of producing properties through our acquisition activity. In addition to the increase in the number of wells on production, the per-well production has increased as we have enhanced our completion techniques with advanced fracture stimulations. In 2012, we expect our cash flow from operations to significantly increase commensurate with our increase in estimated production. If we are able to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, we would expect our production rates and operating cash flows to grow significantly as we move through 2012. We estimate that our 2012 average daily sales volumes will be approximately 19,000 to 21,000 BOE per day as compared to approximately 4,000 BOE per day in 2011.

        Senior Notes.    As discussed above, during 2011, we issued at par $650.0 million of 8.125% Senior Notes due December 1, 2019. The proceeds received from the offer and sale of the Senior Notes was deposited into an escrow account, along with other cash, in an amount equal to 101% of the offering price of the Senior Notes and the interest payable on the Senior Notes to March 22, 2012. At

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December 31, 2011, we held $674.0 million in cash in escrow related to the Senior Notes. In January 2012, we closed the January 2012 Acquisition and all funds were released from escrow. The Company received net proceeds of approximately $632.4 million after deducting discounts and fees. The net proceeds were primarily used to finance the January 2012 Acquisition and repay all borrowings under the second lien credit agreement. The interest on our Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. For further discussion regarding the Senior Notes, please refer to Note 5—Long-Term Debt under Item 8 of this report.

        Credit Facility.    In November 2011, we amended our credit facility pursuant to which we increased our borrowing base to $225.0 million with a maximum credit amount of $750.0 million. This facility, which is currently undrawn, has a maturity date of November 14, 2016. Redetermination of the borrowing base occurs semi-annually, on April 1 and October 1. Additionally, the Company may elect a redetermination of the borrowing base one time during any six month period. We are subject to restrictive covenants under the credit facility. The ability to maintain this facility and borrow additional funds is dependent on a number of variables, including our proved reserves, and assumptions regarding the price at which oil and natural gas can be sold. Further, we expect that our borrowing base will increase with the addition of proved properties as a result of our ongoing drilling and completion activities. For further details on the credit facility please refer to Note 5—Long-Term Debt under Item 8 in this Annual Report.

        Registered Offerings.    Historically, we have financed our operations, property acquisitions and other capital investments from the proceeds of offerings of our equity and debt securities. We currently have on file with the SEC a universal shelf registration statement to allow us to offer an indeterminate amount of securities in the future. Under the registration statement, we may offer from time to time debt securities, common stock, preferred stock, warrants and other securities or any combination of such securities in amounts, prices and on terms announced when and if the securities are offered. The specifics of any future offerings, along with the use of proceeds of any securities offered, will be described in detail in a prospectus supplement at the time of any such offering.

        We believe our cash flows from operations, our existing working capital and increases in our borrowing base, if necessary and available, will be sufficient to meet our planned 2012 capital expenditure budget and to satisfy our 2012 obligations under our Senior Notes and other 2012 contractual commitments. If our existing and potential sources of liquidity were not to be sufficient to satisfy such commitments and to undertake our currently planned expenditures or any revisions thereto, we believe that we have the flexibility in our commitments to alter our drilling program, which may include reducing our rig count and sub-contracting our pressure pumping services agreement. Both of these may incur termination fees as discussed under the heading "Contractual Obligations and Commitments" depending on the timing and contractual requirements of each contract. As we operate the majority of our acreage, we have the ability to adjust our drilling schedule to reflect the changing commodity price or oil field service environment. If necessary, we may conduct an offering of our securities, or reduce our ownership through joint ventures or asset sales. Should we reduce our ownership and relinquish the right to operate certain properties, we would become subject to obligations imposed by others, without the ability to control our drilling schedule. There can be no assurance that any such transactions can be completed or that such transactions would satisfy our operating capital requirements and other commitments. If we were not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned expenditures or restructure our operations, we would be unable to implement our original exploration and drilling program, and we may be unable to service our debt obligations or satisfy our contractual obligations.

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SEC Registration Obligations

        In connection with the sale of the Senior Notes, the Company entered into a registration rights agreement that provides the holders of the Senior Notes certain rights relating to the registration of the Senior Notes under the Securities Act. Pursuant to the registration rights agreement, the Company agreed to conduct a registered exchange offer for the Senior Notes or cause to become effective a shelf registration statement providing for the resale of the Senior Notes, each in accordance with the terms of the agreement. If the Company fails to comply with certain obligations under the agreement, it will be required to pay liquidated damages by way of additional interest on the Senior Notes.

        In addition, we have granted to the sellers in the January 2012 Acquisition certain rights relating to the registration under the Securities Act of the shares issued pursuant to the acquisition.

Operating Results

Production and Sales Volumes, Average Sales Prices, Production Costs, and G&A Expenses

        The Bakken is the only field (as such term is used within the meaning of applicable regulations of the SEC) that contains more than 15% of our total proved reserves. At December 31, 2011, this field contained 99% of our total proved reserves. Our revenues are directly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The commodity prices are largely beyond our control and are difficult to predict. We have seen significant volatility in oil and natural gas prices in recent years. Since early 2009, oil prices have steadily increased while natural gas prices have decreased. We believe that spot market prices reflect worldwide concerns about the global economy, producers' ability to ensure sufficient supply of oil to meet increasing demand amid a host of uncertainties caused by political instability, a fluctuating U.S. dollar, and crude oil refining and natural gas infrastructure constraints. Prices that we have historically received have varied widely depending on the commodity and the location of the sales-points. Conversely, production costs have increased with the expansion of our activity and the overall demand on services in the Williston Basin. The following table discloses our oil and gas production and sales volumes from the Bakken field and from our other fields combined and in total, for the periods indicated:

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Sales Volume (Bakken):

                   

Oil (Bbls)

    1,304,728     402,344     145,181  

Gas (Mcf)

    472,275     11,156     6,092  

Sales Volume (Other):

                   

Oil (Bbls)

    39,812     29,955     37,377  

Gas (Mcf)

    50,379     151,775     214,363  

Sales Volume (Total):

                   

Oil (Bbls)

    1,344,540     432,299     182,558  

Gas (Mcf)

    522,654     162,931     220,455  

Sales volumes (BOE)

    1,431,649     459,454     219,300  

Natural Gas flared (Mcf)(1):

    806,664     282,726     82,660  

Total production volume (Total):

                   

Oil (Bbls)

    1,343,761     432,299     182,558  

Gas (Mcf)

    1,329,318     445,657     303,115  

Production volumes (BOE)

    1,565,314     506,575     233,076  
(1)
Includes production of natural gas that is not included in our sales volumes. All flared gas is related to the Bakken field.

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        Sales prices received, and production costs per BOE for the years ended December 31, 2011, 2010 and 2009 are summarized in the following table:

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Sales Price:

                   

Oil ($/Bbls)

  $ 86.05   $ 69.89   $ 58.35  

Gas ($/Mcf)(1)

  $ 8.22   $ 4.81   $ 2.84  

Commodity Price Risk Management Activities ($/Sales BOE):

                   

Realized gain (loss)

  $ (2.72 ) $ (0.88 ) $  

Production costs ($/Sales BOE):

                   

Lease operating expenses

  $ 8.67   $ 7.03   $ 4.25  

Production and property taxes

  $ 9.04   $ 7.49   $ 5.50  

Gathering, transportation, marketing

  $ 1.07   $ 0.26   $ 0.37  

DDA

  $ 22.40   $ 17.92   $ 14.40  

G&A

  $ 13.62   $ 26.53   $ 38.86  

Stock-based compensation

  $ 3.63   $ 9.70   $ 15.64  

(1)
Average gas price received at the wellhead includes proceeds from natural gas liquids under percentage of proceeds contracts.

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

        Oil sales revenues.    Oil sales revenues increased by $85.5 million to $115.7 million for the year ended December 31, 2011 as compared to oil sales of $30.2 million for the year ended December 31, 2010. In 2011, our crude oil sales averaged 3,684 barrels per day. Our oil sales volume increased 211% to 1,344.5 thousand barrels ("MBbls") in 2011 as compared to 432.3 MBbls in 2010. The volume increase is due to our ongoing Bakken development program. These increases are primarily due to bringing 15.5 net wells on to production in 2011 in addition to commodity price increases. The increased revenue from oil sales in 2011 is attributed to a $78.5 million positive impact due to increased volumes. Additionally, the average price we realized on the sale of our oil increased from $69.89 per barrel for the year ended December 31, 2010, to $86.05 for the year ended December 31, 2011 resulting in a positive impact of $7.0 million in revenue. Overall, 92% of the increase is oil sales revenue was attributed to increased volumes and 8% was attributed to the increase in crude oil prices received.

        Natural gas sales revenues.    Natural gas revenues increased by $3.5 million to $4.3 million for the year ended December 31, 2011 as compared to natural gas revenues of $983,000 for the year ended December 31, 2010. Natural gas sales volumes increased by 360,000 Mcf to 523,000 Mcf for the year ended December 31, 2011. In 2011, our natural gas sales averaged 1,432 Mcf per day. The average price we realized on the sale of our natural gas was $8.22 per Mcf in 2011 compared to $4.81 per Mcf in 2010. The increase in natural gas prices realized resulted in a $500,000 increase in natural gas revenues and the increase in natural gas volumes resulted in a $3.5 million increase in natural gas revenues. Overall, 84% of the increase in natural gas sales revenue was attributed to increased volumes and 16% was attributed to the increase in natural gas prices received. The increase in our natural gas sales volumes is largely a result of production and sales of associated gas from our Bakken properties offset by a decline of our Wyoming assets that historically contributed a majority of our natural gas production. The price realized from sales of our natural gas increased due to the growth of our gas sales from our Bakken properties, which has a higher natural gas liquids content compared to our Wyoming properties. Although the majority of our gas from the Bakken wells-to-date has been flared, late in 2010, we began connecting our wells to third-party pipelines that gather and transport the gas to

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processing plants and sales pipelines. During 2011, we connected the majority of our wells to gas pipelines which allowed us to capture the related sales revenue. Industry-wide in the Williston basin, there is currently a shortage of gas gathering and processing capacity which has limited our ability to sell our gas production. Throughout 2012, we expect to continue to connect our wells to third-party facilities, which should allow additional gas volumes to be gathered, processed and sold.

        Oil and gas production expense.    Our oil and gas production expense increased by $20.1 million to $26.9 million for the year ended December 31, 2011, from $6.8 million for the same period in 2010. The increase is due to a $9.5 million increase in production taxes, a $9.2 million increase in lease operating expenses ("LOE"), and a $1.4 million increase in gathering, transportation and marketing expenses. The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. LOE increased year over year due to a higher number of wells that we operate or participate in. On a per unit basis, LOE increased from $7.03 per barrel sold in 2010 to $8.67 per barrel sold in 2011. As a result of the increase in the number of wells completed during 2011 compared to 2010, we incurred more expense in water disposal costs. The largest cost driver in our Williston Basin operations is the disposal of water used in the well completion operations. We expense the water handling costs once oil production is established. To date, the majority of water has been transported by truck to third party disposal facilities. Late in 2010 and throughout 2011, we have progressed in connecting our wells to third party pipelines that transport water directly to disposal facilities. To date, this activity has been limited to our properties east of the Nesson Anticline in Dunn County, ND. As we have expanded our operations and completion activities to areas not served by water gathering facilities, we have experienced significant increases in water transportation and disposal costs. To reduce water disposal costs, in 2012 we expect to drill water disposal wells on several of our producing areas and construct water gathering systems where appropriate. As we connect existing and future wells to these water gathering systems, we expect our LOE to decrease on a per unit basis. In the fourth quarter 2011, we also incurred an expense of approximately $900,000 or $0.63 per barrel sold to relocate a third-party pipeline. Additionally, throughout 2011, we incurred additional costs to repair roads from the severe weather conditions that resulted in flooding during the spring of 2011.

        Depletion, depreciation, amortization and abandonment liability accretion ("DD&A") expense.    Our depletion, depreciation, amortization and abandonment liability accretion expense increased $23.8 million to $32.1 million for the year ended December 31, 2011, from $8.3 million for the same period in 2010. This increase is due to increased volumes sold in 2011 as sales increased by approximately 972,000 BOE. On a per unit basis, DD&A increased from $17.92 per BOE in 2010 to $22.40 per BOE in 2011. This increase is primarily due to the acquisition of proved reserves related to our 2010 and 2011 acquisitions. Acquired proved reserves are valued at fair market value on the date of acquisition, which contributes to a higher amortization base, as compared to our historical cost of acquiring leasehold and developing our properties. To date, the fair value of our acquired proved reserves has been higher than our historical cost of developing our properties even though the resulting EUR's are equivalent. Therefore, the increase in the ratio of costs subject to amortization to the reserves acquired is greater than our internally developed properties. We believe that, although initially these acquisitions increase our DD&A rate per BOE over the development of the acquired properties, the resulting rates will decline with infill drilling and the addition of the related reserves.

        Additionally, well costs have increased as we began predominantly completing our wells using a greater number of fracture stimulation stages and increased volumes of proppant. These factors have increased the well completion costs, but we believe that the higher upfront costs will generate overall higher returns through greater production volumes and total oil and gas reserves. Currently, because of the early stages of development of our Bakken play, our reserves, especially for undeveloped locations, include the increased well costs, but not the improved reserves. We believe that as our improved results are reflected in our future estimated reserves, the DDA rate per BOE will decrease over time.

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        General and administrative ("G&A") expense.    G&A expense increased by $7.3 million to $19.5 million for the year ended December 31, 2011, from $12.2 million for the same period in 2010. This increase is due to the growth in personnel and related costs as we have expanded our operational activities. Total employees have increased to 74 at year-end 2011 from 35 at year-end 2010. Additionally, in 2011, we incurred approximately $675,000 in transaction costs related to the acquisitions that closed in 2011 and early 2012, as compared to transaction costs of approximately $370,000 in 2010 for the acquisition that closed in 2010. On a per unit basis, G&A decreased from $26.53 per barrel sold in 2010 to $13.62 per barrel sold in 2011. The decrease is primarily due to our increase in production sales from our ongoing Bakken development program. Our oil and natural gas sales volume increased 212% to 1,431.6 MBbls in 2011 as compared to 459.5 MBbls in 2010.

        Our G&A expense includes the non-cash expense for stock-based compensation for stock options and share grants under our 2007 Stock Incentive Plan. For the years ended December 31, 2011, this expense was $5.2 million as compared to $4.5 million in 2010.

        Operating income.    Our operating income was approximately $41.5 million for the year ended December 31, 2011, as compared to approximately $3.8 million for the same period in 2010. This 999% increase in operating income is attributed to our on-going successful completions of wells in our Bakken play as well as crude oil price improvement for the year ended 2011 as compared to 2010.

        Loss on commodity price risk management activities.    For the year ended December 31, 2011, we incurred a total loss on our risk management activities of $20.1 million. This loss is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This loss was comprised of approximately $3.9 million of realized losses for transactions that were settled during 2011 and $16.2 million of unrealized losses for the mark-to-market of forward transactions. The unrealized loss is a non-cash adjustment for the value of our risk management transactions at December 31, 2011. These transactions will continue to change in value until the transactions are settled and we will likely add to our hedging program. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.

        Interest income (expense), net.    For the year ended December 31, 2011, we recognized interest expense of approximately $19.0 million, as compared to $82,000 for the same period in 2010. Included in interest expense in 2011 was approximately $11.5 million of financing costs related to a stand-by bridge financing that we obtained to enable the closing of the properties in the January 2012 Acquisition in the event that we were unable to fund the acquisition with proceeds from the Senior Notes. As the bridge financing was not utilized, all financing costs of approximately $11.5 million were expensed in the fourth quarter of 2011. Also during 2011, as a result of the extinguishment of the second lien credit agreement in January 2012, we accelerated amortization of the related capitalized deferred financing costs, which resulted in additional amortization expense of approximately $2.4 million.

        We recognized interest expense during 2011 of approximately $4.0 million related to the credit facilities and the issuance of $650 million in 8.125% Senior Notes in November 2011. Additionally, we capitalized interest costs of $8.4 million and $470,000 for the years ended December 31, 2011 and 2010, respectively.

        Net income.    Our net income was approximately $3.9 million for the year ended December 31, 2011, as compared to a net loss of $2.4 million for 2010. Although our revenue, net of production expenses, was higher compared to 2010, our 2011 net income was negatively impacted by increased DD&A, G&A, interest expense and, most significantly, the loss on price risk management activities discussed above.

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Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

        Oil sales revenues.    Oil sales revenues increased by $19.5 million to $30.2 million for the year ended December 31, 2010 as compared to oil sales of $10.7 million for the year ended December 31, 2009. Our oil sales volume increased 137% to 432.3 MBbls in 2010 as compared to 182.6 MBbls in 2009. The increased revenue from oil sales in 2010 is attributed to a $17.4 million positive impact due to increased volumes. Additionally, the average price we realized on the sale of our oil increased from $58.35 per barrel for the year ended December 31, 2009, to $69.89 for the year ended December 31, 2010 resulting in a positive impact of $2.1 million in revenue.

        Natural gas sales revenues.    Natural gas sales volumes decreased by 57,000 Mcf to 163,000 Mcf for the year ended December 31, 2010. The average price we realized on the sale of our natural gas was $4.81 per Mcf in 2010 compared to $2.84 per Mcf in 2009. The increase in natural gas prices realized resulted in a $435,000 increase in natural gas revenue while the decline in natural gas volumes resulted in a decline in natural gas revenue by $277,000 for total increase of our gas sales revenue of approximately $158,000. The decline in our natural gas sales volumes is largely a result of our focus on the development of our Bakken properties as opposed to our Wyoming assets that historically have contributed a majority of our natural gas production. Although our Bakken wells do produce associated gas, at year end 2010, most of this gas had been flared. Late in 2010, we began connecting our wells to third party pipelines that will gather and transport the gas to processing plants and sales pipelines.

        Oil and gas production expense.    Our oil and gas production expense increased by $4.6 million to $6.8 million for the year ended December 31, 2010, from $2.2 million for the same period in 2009. The increase is primarily due to a $2.2 million increase in production taxes and a $2.4 million increase in LOE. The production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. LOE increased year over year due to a higher number of wells that we operate or participate in. On a per unit basis, LOE increased from $4.25 per barrel sold in 2009 to $7.03 in 2010. This increase is related to higher operating costs primarily in our Williston Basin activities. The largest cost driver in our Williston Basin operations is the disposal of water used in the well completion operations. We expense the water handling costs once oil production is established. To date, this water has been transported by truck to third party disposal facilities. Late in 2010, we began connecting our wells to third party pipelines that will transport water directly to disposal facilities.

        Depletion, depreciation, amortization and abandonment liability accretion expense.    Our DD&A expense increased by $5.0 million to $8.2 million for the year ended December 31, 2010, from $3.2 million for the same period in 2009. This increase is due to increased volumes sold in 2010 as sales increased by approximately 240,000 BOE. On a per unit basis, DD&A increased from approximately $14.40 per barrel sold in 2009 to $17.92 per barrel sold in 2010. This increase is primarily due to increased well costs as compared to reserves as estimated in our annual reserve report. In 2010, we have predominantly completed our wells using a greater number of fracture stimulation stages and increased volumes of proppant. These factors have increased the well completion costs but we believe that the higher upfront costs will generate overall higher returns through greater production volumes and total oil and gas reserves. Currently, because of the early stages of development of our Bakken play, our reserves include the increased well costs but not the improved reserves.

        General and administrative expense.    G&A expense increased by $3.7 million to $12.2 million for the year ended December 31, 2010, from $8.5 million for the same period in 2009. This increase is due to the growth in personnel and related costs as we have expanded our operational activities. Total employees have increased to 35 at year-end 2010 from 15 at year-end 2009. Also contributing to the increase are costs associated with acquisition of the properties acquired in November 2010 of approximately $370,000. On a per unit basis, G&A decreased from $38.86 per barrel sold in 2009 to $26.53 per barrel sold in 2010. The decrease is primarily due to our increase in production sales from our ongoing Bakken development program. Our oil and natural gas sales volume increased 110% to 459.5 MBbls in 2010 as compared to 219.3 MBbls in 2009.

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        Our G&A expense includes the non-cash expense for stock-based compensation for stock options and share grants under our 2007 Stock Incentive Plan. For the twelve months ended December 31, 2010, this expense was $4.5 million as compared to $3.4 million in 2009. Approximately $600,000 of the year over year increase was due to the use of shares of common stock in lieu of cash for a portion of the 2010 executive bonus award.

        Operating income.    Our operating income was approximately $3.8 million for the year ended December 31, 2010, as compared to approximately $(2.6) million for the same period in 2009. This 246% increase in operating income is attributed to our on-going successful completions of wells in our Bakken play as well as crude oil price improvement for the year ended 2010 as compared to 2009.

        Loss on commodity price risk management activities.    For the twelve months ended December 31, 2010 we incurred a total loss on our risk management activities of $6.1 million. This loss is a result of our hedging program used to mitigate our exposure to commodity price fluctuations. This loss was comprised of approximately $400,000 of realized losses for transactions that were settled in the fourth quarter of 2010 and $5.7 million of unrealized losses for the mark-to-market of forward transactions. The unrealized loss is a non-cash adjustment for the value of our risk management transactions at December 31, 2010. These transactions will continue to change in value until they are settled. Therefore, we expect our net income to reflect the volatility of commodity price forward markets. Our cash flows will only be affected upon settlement of the transactions at the current market prices at that time.

        Net loss.    Our net loss was approximately $2.4 million for the year ended December 31, 2010, as compared to a net loss of $2.6 million for 2009. Although our revenue, net of production expenses, was higher compared to 2009, our 2010 net loss was negatively impacted by increased DD&A, G&A and, most significantly, the loss on price risk management activities discussed above.

Financial Instruments and Other Instruments

        As at December 31, 2011, our financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (see Note 6—Commodity Derivative Instruments under Item 8 of this Annual Report) and long-term debt (See Note 5—Long-Term Debt under Item 8 of this Annual Report). The carrying values of cash equivalents and accounts receivable, accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of our credit facility approximates fair value as it bears interest at variable rates over the term of the loan. Please refer to Note 8 to Financial Statements under Item 8 of this Annual Report for further discussion on the fair value of the second lien credit agreement and the Senior Notes. Our management believes that we are not exposed to significant interest, currency or credit risks arising from these financial instruments.

Research and Development

        As an exploration and production natural resource company, we do not normally engage in research and development ("R&D"). There were no R&D activities, or R&D expenditures made in the last three fiscal years.

Off-balance sheet arrangements

        We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Contractual Obligations and Commitments

        The following table lists as of December 31, 2011, information with respect to our known contractual obligations:

 
  Payments due by Period  
 
  Total   Less than
1 year
  1-3 years   3-5 years   More than
5 years
 
 
  (In thousands)
 

Contractual Obligations

                               

Office Lease(a)

  $ 2,949   $ 581   $ 1,198   $ 1,170   $  

Drilling Rig Obligations(b)

    36,479     28,950     7,529          

Pressure Pumping Services Obligation(c)

    36,000     24,000     12,000          

First Lien Credit Agreement(d)

    4,008     844     1,688     1,476      

Second Lien Credit Agreement(e)

    103,343     103,343              

Senior Notes and Interest Payable(f)

    1,073,675     53,987     105,625     105,625     808,438  
                       

Total

  $ 1,256,454   $ 211,705   $ 128,040   $ 108,271   $ 808,438  
                       
(a)
We lease office space in Denver, Colorado and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on October 31, 2016. The Dickinson, North Dakota lease expires December 31, 2013. Total rental commitments under non-cancelable leases for office space were $2.9 million at December 31, 2011.

(b)
As of December 31, 2011 we had five drilling rig contracts under long term contracts, of which two of the contracts expire in 2012 and three expire in 2013. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $36.5 million as of December 31, 2011 as required under the varying terms of such contracts. As part of the January 2012 Acquisition, the Company assumed a sixth drilling rig contract commencing on January 15, 2012. In the event of early termination under this contract, the Company would be obligated to pay an additional $5.7 million. This sixth rig was not included in the above schedule.

(c)
In October 2011, we amended our pressure pumping services contract to provide 24-hour frac crew availability for 30 days per month. The new terms commence in January 2012. Under the new agreement in the event of early contract termination, the Company would be obligated to pay approximately $36.0 million for the first six months and then the obligation would reduce monthly thereafter.

(d)
Calculated assuming no borrowings outstanding under our credit facility. As of December 31, 2011 and the date of this filing, the Company had no outstanding borrowings under the credit facility. Interest on the revolving loans is payable at one of the following two variable rates: the alternate base rate for ABR loans or the adjusted LIBO rate for eurodollar loans, as selected by the Company, plus an additional percentage that can vary on a daily basis and is based on the daily unused portion of the facility. This additional percentage is referred to as the "Applicable Margin" and varies depending on the type of loan. The Applicable Margin for the ABR loans is a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The Applicable Margin on the adjusted LIBO rate is a sliding scale of 1.75% to 2.75%, depending on borrowing base usage. Additionally, the credit facility provides for a borrowing base fee of 0.5% and a commitment fee of 0.375% to 0.50%, depending on borrowing base usage. For further discussion regarding the terms of the credit facility please refer to Note 5—Long-Term Debt under Item 8 in this Annual Report.

(e)
As of December 31, 2011, we had $100.0 million in outstanding borrowings under the second lien credit agreement, which accrued interest at a rate of approximately 9.5%. On January 10, 2012, we repaid all of the outstanding debt under the second lien credit agreement, and incurred a

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    $3.0 million prepayment penalty in connection therewith, and also paid accrued interest of $343,000. The second lien credit agreement was terminated and thus the above schedule does not assume any additional payments. For further discussion regarding the terms of the second lien credit agreement please refer to Note 5—Long-Term Debt under Item 8 in this Annual Report.

(f)
Calculated assuming $650.0 million of 8.125% Senior Notes outstanding due December 1, 2019. The interest on the Senior Notes is payable on June and December 1 of each year, beginning June 1, 2012. For further discussion regarding the terms of the Senior Notes please refer to Note 5—Long-Term Debt under Item 8 in this Annual Report.

        The above contractual obligations schedule does not include future anticipated settlement of derivative contracts or estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties, as we cannot determine with accuracy the timing of such payments.

        As is customary in the oil and gas industry, the Company may at times have commitments in place to reserve or earn certain acreage positions or wells. If the Company does not meet such commitments, the acreage positions or wells may be lost.

Critical Accounting Policies and Estimates

        The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures. Actual results may differ from these estimates under different assumptions or conditions. For a detailed summary of our significant accounting policies, please refer to Note 2—Basis of Presentation and Significant Accounting Policies under Item 8 of this Annual Report. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

Oil and Natural Gas Reserves Estimates

        Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

        We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our Company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil and natural gas, that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of

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that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation required by ASC Topic 932, Extractive Activities—Oil and Gas, requires us to apply a 10% discount rate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31 of each year and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.

Oil and Natural Gas Properties, Depletion and Full Cost Ceiling Test

        We follow the full cost method of accounting for oil and natural gas properties. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and exploitation and development of oil and natural gas reserves are capitalized. Such capitalized costs include costs associated with lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and natural gas wells, and salaries, benefits and other internal salary related costs directly attributable to these activities. Proceeds from the disposition of oil and natural gas properties are generally accounted for as a reduction in capitalized costs, with no gain or loss recognized. Depletion of the capitalized costs of oil and natural gas properties, including estimated future development costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves on a quarterly basis. The capitalized costs are amortized over the life of the reserves associated with the assets, with the amortization being expensed as depletion in the period that the reserves are produced. This depletion expense is calculated by dividing the period's production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the sum of the capitalized investment and estimated future development costs associated with the investment. Changes in our reserve estimates will therefore result in changes in our depletion expense per unit. Costs associated with production and general corporate activities are expensed in the period incurred. Unproved property costs not subject to amortization consist primarily of leasehold and seismic costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as undeveloped areas are tested. Unproved oil and natural gas properties are not amortized, but are assessed, at least annually, for impairment either individually or on an aggregated basis to determine whether we are still actively pursuing the project and whether the project has been proven, either to have economic quantities of reserves or that economic quantities of reserves do not exist.

        Under full cost accounting rules, capitalized costs of oil and natural gas properties, excluding costs associated with unproved properties, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated twelve month arithmetic average of the prices in effect on the first day of each month of the relevant period and requires a write down for accounting purposes if the ceiling is exceeded.

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Derivative Instruments

        The Company has entered into commodity derivative instruments, primarily utilizing swaps or "no premium" collars to reduce the effect of price changes on a portion of our future oil production. The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income. We value our derivative instruments by obtaining independent market quotes, as well as using industry-standard models that consider various assumptions, including quoted forward prices for commodities, risk free interest rates, and estimated volatility factors, as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or us, as appropriate. We utilize the counterparties' valuations to assess the reasonableness of our valuations. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. For additional discussion, please refer to Note 6—Commodity Derivative Instruments under Item 8 of this Annual Report.

Business Combinations

        We have accounted for all of our business combinations to date using the purchase method, which is the only method permitted under FASB ASC Topic 805, Business Combinations, and involves the use of significant judgment. The Company adopted the updated guidance of ASC 805 effective January 1, 2009 and applied it to the acquisition of its 2010 Acquired Properties, June 2011 Acquired Properties, October 2011 Acquired Properties and January 2012 Acquired Properties (with each of such terms being as defined below). For a detailed summary of our acquisitions accounted for under ASC 805, please refer to Note 4—Acquisitions and Divestitures under Item 8 of this Annual Report.

        Under the purchase method of accounting, a business combination is accounted for at a purchase price based upon the fair value of the consideration given. The assets and liabilities acquired are measured at their fair values, and the purchase price is allocated to the assets and liabilities based upon these fair values. The excess of the cost of an acquired entity, if any, over the net amounts assigned to assets acquired and liabilities assumed is recognized as goodwill. The excess of the fair value of assets acquired and liabilities assumed over the cost of an acquired entity, if any, is recognized immediately to earnings as a gain from bargain purchase.

        Determining the fair values of the assets and liabilities acquired involves the use of judgment, since some of the assets and liabilities acquired do not have fair values that are readily determinable. Different techniques may be used to determine fair values, including market prices (where available), appraisals, comparisons to transactions for similar assets and liabilities, and present value of estimated future cash flows, among others. Since these estimates involve the use of significant judgment, they can change as new information becomes available.

        Each of the business combinations completed during the prior two years consisted of oil and gas properties. The consideration we have paid to acquire these properties was entirely allocated to the fair value of the assets acquired and liabilities assumed at the time of acquisition. Consequently, there was no goodwill nor any bargain purchase gains recognized on any of our business combinations.

Asset Retirement Obligations

        We are required to recognize an estimated liability for future costs associated with the abandonment of our oil and gas properties including without limitation the costs of reclamation of our

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drilling sites, storage and transmission facilities and access roads. We base our estimate of the liability on the industry experience of our management and on our current understanding of federal and state regulatory requirements. Our present value calculations require us to estimate the economic lives of our properties, assume what future inflation rates apply to external estimates and determine the credit-adjusted risk-free rate to use. In periods subsequent to the initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A over the life of the oil and gas property.

Income Tax Expense

        Income taxes reflect the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying current tax rates to the differences between financial statement and income tax reporting. We have recognized a full valuation allowance against our net deferred taxes because we cannot conclude that it is more likely than not that the net deferred tax assets will be realized as a result of estimates of our future operating income based on current oil and natural gas commodity pricing. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, we consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. Future events or new evidence which may lead the Company to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings; consistent and sustained pre-tax earnings; sustained or continued improvements in oil and natural gas commodity prices; continued increases in production and proved reserves from the Williston Basin. The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods.

Revenue Recognition

        Our revenue recognition policy is significant because revenue is a key component of our results of operations and of the forward-looking statements contained in our analysis of liquidity and capital resources. We derive our revenue primarily from the sale of crude oil and natural gas. We report revenue as the gross amounts we receive before taking into account production taxes and transportation costs, which are reported as separate expenses. We record revenue in the month our production is delivered to the purchaser, but payment is generally received 30 to 90 days after the date of production. At the end of each month, we make estimates of the amount of production that we delivered to the purchaser and the price we will receive. We record the variances between our estimates and the actual amounts we receive in the month payment is received.

Stock-Based Compensation

        We have a stock-based compensation plan that includes restricted stock shares, restricted stock units ("RSUs"), performance awards ("PAs"), stock awards, and stock options issued to employees, officers and directors as more fully described in Note 11—Share-Based Payments under Item 8 of this Annual Report. We record expense associated with the fair value of stock-based compensation in accordance with ASC 718, Stock Based Compensation. We record compensation expense associated with

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the issuance of restricted stock shares and RSUs based on the estimated fair value of these awards determined at the time of grant. The PAs are payable in cash, except the Company may, in its discretion, determine to pay out the PAs on the vesting date through the issuance of shares of our common stock. Consequently, as the remaining PAs will likely be settled in cash, a liability is recorded and remeasured at each quarter.

PV-10

        The pre-tax present value of future net cash flows, or PV-10, is a non-GAAP measure because it excludes income tax effects. Management believes that pre-tax cash flow amounts are useful for evaluative purposes since future income taxes, which are affected by a company's unique tax position and strategies, can make after-tax amounts less comparable. We derive PV-10 based on the present value of estimated future revenues to be generated from the production of proved reserves, net of estimated production and future development costs and future plugging and abandonment costs, using the twelve-month arithmetic average of the first of the month prices without giving effect to hedging activities or future escalation, costs as of the date of estimate without future escalation, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion, amortization and impairment and income taxes, and discounted using an annual discount rate of 10%. The following table reconciles the standardized measure of future net cash flows to PV-10 as of the dates shown (in thousands):

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Standardized measure of discounted future net cash flows

  $ 659,975   $ 154,568   $ 39,063  

Add: Present value of future income tax discounted at 10%

    190,706     6,560      
               

PV-10

  $ 850,681   $ 161,128   $ 39,063  
               

Recently Issued Accounting Pronouncements

        For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the section titled Recent Accounting Pronouncements under Note 2—Basis of Presentation and Significant Accounting Policies under Item 8 of this Annual Report.

Effects of Pricing and Inflation

        The demand for oil field products and services has increased in the Williston Basin beginning in 2010 and continued throughout 2011. Typically, as prices for oil and natural gas increase, so do the associated costs. As oil and natural gas prices decline, we would expect associated costs to decline, however, there may be a lag or the changes may be disproportionate to the lower prices. Material changes in prices also impact the current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, depletion expense, impairment assessments of oil and gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        This section provides information about derivative financial instruments we use to manage commodity price volatility. Due to the historical volatility of crude oil prices, we have implemented a hedging strategy aimed at reducing the variability of the prices we receive for our production and providing a minimum revenue stream. Currently, we enter into derivative transactions such as collars and fixed price swaps in order to hedge our exposure to changes in commodity prices. All contracts are settled with cash and do not require the delivery of a physical quantity to satisfy settlement. While this hedging strategy may result in us having lower revenues than we would have if we were unhedged in times of higher oil prices, management believes that the stabilization of prices and protection afforded us by providing a revenue floor on a portion of our production is beneficial. We may, from time to time, opportunistically restructure existing derivative contracts or enter into new transactions to effectively modify the terms of current contracts in order to improve the pricing parameters in existing contracts or realize the current value of our existing positions. We may use the proceeds from such transactions to secure additional contracts for periods in which we believe there is additional unmitigated commodity price risk or for other corporate purposes.

        This section also provides information about our interest rate risk below.

Commodity Price Risk

        Our primary market risk is market changes in oil and natural gas prices. The market prices for oil and natural gas have been highly volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. Currently, we utilize swaps and "no premium" collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into derivative instruments for trading purposes. All hedges are accounted for using mark-to-market accounting.

        We use costless collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements. These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When the settlement price for a period is below the floor price, our counterparty is required to pay us.

        We use swaps to fix the sales price for our anticipated future oil production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us.

        The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., is currently a party to derivative contracts with two counterparties, and the Company is a guarantor of Kodiak Oil & Gas (USA) Inc. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. Although the instruments are valued using indices published by established exchanges, the instruments are traded directly with the counterparties. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

        The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit the Company's ability to benefit from favorable

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price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.

        The Company's commodity derivative contracts as of December 31, 2011 are summarized below:

Contract Type
  Counterparty   Basis(1)   Quantity(Bbl/d)   Strike Price ($/Bbl)   Term

Collar

  Wells Fargo Bank, N.A.   NYMEX     400   $70.00/$95.56   Jan 1, 2012 - Dec 31, 2012

Collar

  Wells Fargo Bank, N.A.   NYMEX     230   $85.00/$117.73   Jan 1, 2012 - Dec 31, 2012

Collar

  Shell Trading (U.S.)   NYMEX     500   $85.00 - $117.00   Jan 1, 2012 - Dec 31, 2013

Collar

  Wells Fargo Bank, N.A.   NYMEX     300 - 425   $85.00 - $102.75   Jan 1, 2013 - Dec 31, 2015

 

Contract Type
  Counterparty   Basis(1)   Quantity(Bbl/d)   Swap Price ($/Bbl)   Term

Swap

  Wells Fargo Bank, N.A.   NYMEX     100   $ 84.00   Jan 1, 2012 - Dec 31, 2012

Swap

  Wells Fargo Bank, N.A.   NYMEX     136   $ 88.30   Jan 1, 2012 - Dec 31, 2012

Swap

  Wells Fargo Bank, N.A.   NYMEX     24   $ 90.28   Jan 1, 2012 - Dec 31, 2012

Swap

  Wells Fargo Bank, N.A.   NYMEX     500   $ 85.00   Jan 1, 2012 - Dec 31, 2012

Swap

  Wells Fargo Bank, N.A.   NYMEX     1,000   $ 85.07   Jan 1, 2012 - Dec 31, 2012

Swap

  Shell Trading (U.S.)   NYMEX     250   $ 85.01   Jan 1, 2012 - Dec 31, 2012

Swap

  Shell Trading (U.S.)   NYMEX     2,000   $ 96.88   Jan 1, 2012 - Dec 31, 2012
                     

2012 Total/Average

      4,010   $ 91.06          
                     

Swap

  Wells Fargo Bank, N.A.   NYMEX     79   $ 84.00   Jan 1, 2013 - Dec 31, 2013

Swap

  Wells Fargo Bank, N.A.   NYMEX     427   $ 88.30   Jan 1, 2013 - Dec 31, 2013

Swap

  Wells Fargo Bank, N.A.   NYMEX     24   $ 90.28   Jan 1, 2013 - Dec 31, 2013

Swap

  Wells Fargo Bank, N.A.   NYMEX     500   $ 85.00   Jan 1, 2013 - Dec 31, 2013

Swap

  Wells Fargo Bank, N.A.   NYMEX     400   $ 85.07   Jan 1, 2013 - Dec 31, 2013

Swap

  Wells Fargo Bank, N.A.   NYMEX     425   $ 93.20   Jan 1, 2013 - Dec 31, 2013

Swap

  Shell Trading (U.S.)   NYMEX     250   $ 85.01   Jan 1, 2013 - Dec 31, 2013
                     

2013 Total/Average

      2,105   $ 87.36          
                     

Swap

  Wells Fargo Bank, N.A.   NYMEX     69   $ 84.00   Jan 1, 2014 - Dec 31, 2014

Swap

  Wells Fargo Bank, N.A.   NYMEX     360   $ 88.30   Jan 1, 2014 - Dec 31, 2014

Swap

  Wells Fargo Bank, N.A.   NYMEX     21   $ 90.28   Jan 1, 2014 - Dec 31, 2014

Swap

  Wells Fargo Bank, N.A.   NYMEX     350   $ 93.20   Jan 1, 2014 - Dec 31, 2014

Swap

  Wells Fargo Bank, N.A.   NYMEX     1,000   $ 85.07   Jan 1, 2014 - Dec 31, 2014
                     

2014 Total/Average

      1,800   $ 87.32          
                     

Swap

  Wells Fargo Bank, N.A.   NYMEX     59   $ 84.00   Jan 1, 2015 - Oct 31, 2015

Swap

  Wells Fargo Bank, N.A.   NYMEX     317   $ 88.30   Jan 1, 2015 - Sept 30, 2015

Swap

  Wells Fargo Bank, N.A.   NYMEX     46   $ 90.28   Jan 1, 2015 - Oct 31, 2015

Swap

  Wells Fargo Bank, N.A.   NYMEX     300   $ 93.20   Jan 1, 2015 - Dec 31, 2015

Swap

  Wells Fargo Bank, N.A.   NYMEX     1,000   $ 85.07   Jan 1, 2015 - Dec 31, 2015
                     

2015 Total/Average

      1,625   $ 87.13          
                     

        Subsequent to December 31, 2011, the Company entered into additional commodity derivative contracts as summarized below:

Contract Type
  Counterparty   Basis(1)   Quantity(Bbl/d)   Swap Price ($/Bbl)   Term

Swap

  Wells Fargo Bank, N.A.   NYMEX     1,000   $102.05   Mar 1, 2012 - Dec 31, 2012

Swap

  Credit Suisse International   NYMEX     500   $106.85   Mar 1, 2012 - Dec 31, 2012

Swap

  Wells Fargo Bank, N.A.   NYMEX     1,000   $104.13   Jan 1, 2013 - Dec 31, 2013

(1)
NYMEX refers to quoted prices on the New York Mercantile Exchange

        We determine the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company's own credit rating. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it is of substantial credit quality and has the financial resources and willingness to meet its

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potential repayment obligations associated with the derivative transactions. For further details regarding our derivative contracts please refer to Note 6—Commodity Derivative Instruments under Item 8 in this Annual Report.

Interest Rate Risk

        At December 31, 2011, we had $650 million 8.125% Senior Notes outstanding due December 1, 2019, all of which has fixed rate interest.

        In addition, as of December 31, 2011, we had (i) $225.0 million available to us under our credit facility, none of which was drawn at year-end and (ii) $100.0 million outstanding under our second lien credit agreement, which was paid off and terminated following year-end. Both of these credit arrangements bear interest at variable rates. Assuming we had the maximum amount outstanding at December 31, 2011 under our credit facility of $225.0 million, and given the balance under our second lien credit agreement at December 31, 2011 of $100.0 million, a 1.0% increase in interest rates would result in additional annualized interest expense of $3.3 million.

        For a detailed discussion of the foregoing credit arrangements, including a discussion of the applicable interest rates, please refer to Note 5—Long-Term Debt under Item 8 in this Annual Report.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of Kodiak Oil & Gas Corp.

        We have audited the accompanying consolidated balance sheet of Kodiak Oil & Gas Corp. (the "Company") as of December 31, 2011, and the related consolidated statements of operations, stockholders' equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Kodiak Oil & Gas Corp. at December 31, 2011, and the consolidated results of its operations and its cash flows for the year then ended , in conformity with U.S. generally accepted accounting principles.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Kodiak Oil & Gas Corp.'s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2012 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Denver, Colorado
February 28, 2012

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders
Kodiak Oil & Gas Corp.

        We have audited the consolidated balance sheet of Kodiak Oil & Gas Corp. and subsidiaries as of December 31, 2010, and the related consolidated statements of operations, stockholders' equity and cash flows for each of the two years in the period ended December 31, 2010. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Kodiak Oil & Gas Corp. and subsidiaries as of December 31, 2010, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

/s/ Hein & Associates LLP

Denver, Colorado
March 3, 2011

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KODIAK OIL & GAS CORP.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

 
  December 31,
2011
  December 31,
2010
 

ASSETS

             

Current Assets:

             

Cash and cash equivalents

  $ 81,604   $ 101,198  

Cash held in escrow

    12,194      

Accounts receivable

             

Trade

    28,835     11,328  

Accrued sales revenues

    21,974     4,578  

Inventory, prepaid expenses and other

    24,294     18,212  
           

Total Current Assets

    168,901     135,316  
           

Oil and gas properties (full cost method), at cost:

             

Proved oil and gas properties

    598,065     205,360  

Unproved oil and gas properties

    263,462     107,254  

Wells in progress

    78,505     21,418  

Equipment and facilities

    11,186     2,429  

Less-accumulated depletion, depreciation, amortization, and accretion

    (135,586 )   (103,799 )
           

Net oil and gas properties

    815,632     232,662  
           

Cash held in escrow

   
691,764
   
 

Property and equipment, net of accumulated depreciation of $618 at December 31, 2011 and $377 at December 31, 2010

    1,276     366  

Deferred financing costs, net of amortization of $15,029 at December 31, 2011 and $83 at December 31, 2010

    21,904     1,593  
           

Total Assets

  $ 1,699,477   $ 369,937  
           

LIABILITIES AND STOCKHOLDERS' EQUITY

             

Current Liabilities:

             

Accounts payable and accrued liabilities

  $ 78,402   $ 22,805  

Accrued interest payable

    5,808     374  

Commodity price risk management liability

    11,925     2,248  
           

Total Current Liabilities

    96,135     25,427  
           

Noncurrent Liabilities:

             

Credit facilities

    100,000     40,000  

Senior notes

    650,000      

Commodity price risk management liability

    10,035     3,495  

Asset retirement obligations

    3,627     1,968  
           

Total Noncurrent Liabilities

    763,662     45,463  
           

Total Liabilities

    859,797     70,890  
           

Commitments and Contingencies—Note 14

             

Stockholders' Equity:

             

Common stock—no par value; unlimited authorized

             

Issued and outstanding: 257,987,413 shares as of December 31, 2011 and 178,168,205 shares as of December 31, 2010

    944,070     407,312  

Accumulated deficit

    (104,390 )   (108,265 )
           

Total Stockholders' Equity

    839,680     299,047  
           

Total Liabilities and Stockholders' Equity

  $ 1,699,477   $ 369,937  
           

   

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Revenues:

                   

Oil sales

  $ 115,692   $ 30,212   $ 10,652  

Gas sales

    4,294     783     625  
               

Total revenues

    119,986     30,995     11,277  
               

Operating expenses:

                   

Oil and gas production

    26,885     6,795     2,220  

Depletion, depreciation, amortization and accretion

    32,068     8,234     3,159  

General and administrative

    19,495     12,190     8,522  
               

Total operating expenses

    78,448     27,219     13,901  
               

Operating income (loss)

    41,538     3,776     (2,624 )

Other income (expense):

                   

Loss on commodity price risk management activities

    (20,114 )   (6,146 )    

Interest income (expense), net

    (18,887 )   (39 )   53  

Other income

    1,338     7     8  
               

Total other income (expense)

    (37,663 )   (6,178 )   61  
               

Net income (loss)

  $ 3,875   $ (2,402 ) $ (2,563 )
               

Net income (loss) per common share:

                   

Basic

  $ 0.02   $ (0.02 ) $ (0.02 )
               

Diluted

  $ 0.02   $ (0.02 ) $ (0.02 )
               

Weighted average common shares outstanding:

                   

Basic

    197,579,298     131,444,440     103,688,733  
               

Diluted

    200,551,992     131,444,440     103,688,733  
               

   

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

STATEMENTS OF STOCKHOLDERS' EQUITY

(In thousands)

 
  Common Stock
Shares
  Common
Stock
  Accumulated
Deficit
  Total Stockholders'
Equity
 

Balance January 1, 2009:

    95,129   $ 136,298   $ (103,300 ) $ 32,998  

Issuance of stocks for cash:

                         

—pursuant to equity offering

    23,400     37,560         37,560  

—pursuant to exercise of options

    351     333         333  

Share issuance costs

        (1,829 )       (1,829 )

Stock-based compensation

        3,429         3,429  

Net loss

            (2,563 )   (2,563 )
                   

Balance December 31, 2009:

    118,880   $ 175,791   $ (105,863 ) $ 69,928  
                   

Issuance of stocks for cash:

                         

—pursuant to equity offering

    57,500     237,188         237,188  

—pursuant to exercise of options

    1,688     3,236         3,236  

Share issuance costs

        (12,758 )       (12,758 )

Restricted stock issued

    100     261         261  

Stock-based compensation

        3,594         3,594  

Net loss

            (2,402 )   (2,402 )
                   

Balance December 31, 2010:

    178,168   $ 407,312   $ (108,265 ) $ 299,047  
                   

Issuance of stocks for cash:

                         

—pursuant to equity offering

    75,900     542,685         542,685  

—pursuant to exercise of options

    995     1,305         1,305  

Shares issued in connection with acquisition

    2,500     14,425         14,425  

Share issuance costs

        (27,450 )       (27,450 )

Restricted stock issued

    424     593         593  

Stock-based compensation

        5,200         5,200  

Net income

            3,875     3,875  
                   

Balance December 31, 2011:

    257,987   $ 944,070   $ (104,390 ) $ 839,680  
                   

   

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Cash flows from operating activities:

                   

Net income (loss)

  $ 3,875   $ (2,402 ) $ (2,563 )

Reconciliation of net income (loss) to net cash

                   

provided by operating activities:

                   

Depletion, depreciation, amortization and accretion

    32,068     8,234     3,159  

Amortization of deferred financing costs

    15,029     83     25  

Unrealized loss on commodity price risk management activities, net

    16,217     5,743      

Stock-based compensation

    5,200     4,456     3,429  

Changes in current assets and liabilities:

                   

Accounts receivable-trade

    (17,507 )   (8,765 )   (628 )

Accounts receivable-accrued sales revenue

    (17,396 )   (2,668 )   (1,392 )

Prepaid expenses and other

    (2,082 )   (544 )   3,072  

Accounts payable and accrued liabilities

    13,075     5,804     4,294  

Accrued interest payable

    5,434     374      
               

Net cash provided by operating activities

    53,913     10,315     9,396  
               

Cash flows from investing activities:

                   

Oil and gas properties

    (538,615 )   (178,540 )   (24,290 )

Sale of oil and gas properties

    3,264          

Prepaid tubular goods

    (15,490 )   (18,778 )   (3,834 )

Equipment, facilities and other

    (9,908 )   (2,691 )   (278 )

Deposit on acquisition

    (30,000 )       246  
               

Net cash used in investing activities

    (590,749 )   (200,009 )   (28,156 )
               

Cash flows from financing activities:

                   

Borrowings under credit facilities

    350,808     97,308      

Repayments under credit facilities

    (290,808 )   (57,308 )    

Proceeds from the issuance of senior notes

    650,000          

Proceeds from the issuance of common shares

    543,990     240,424     37,893  

Cash held in escrow

    (673,958 )        

Debt and share issuance costs

    (62,790 )   (14,417 )   (1,829 )
               

Net cash provided by financing activities

    517,242     266,007     36,064  
               

Increase (decrease) in cash and cash equivalents

    (19,594 )   76,313     17,304  

Cash and cash equivalents at beginning of the period

    101,198     24,885     7,581  
               

Cash and cash equivalents at end of the period

  $ 81,604   $ 101,198   $ 24,885  
               

Supplemental cash flow information:

                   

Oil & gas property accrual included in Accounts payable and accrued liabilities

  $ 52,541   $ 9,426   $ 601  
               

Oil & gas property acquired through common stock

  $ 14,425   $   $  
               

Cash paid for interest

  $ 6,898   $ 176   $  
               

   

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE CONSOLIDATED FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization

Description of Operations

        Kodiak Oil & Gas Corp. and its subsidiary ("Kodiak" or the "Company") is a public company listed for trading on the New York Stock Exchange under the symbol: "KOG". The Company's corporate headquarters are located in Denver, Colorado, USA. The Company is an independent energy company engaged in the exploration, exploitation, development, acquisition and production of crude oil and natural gas entirely in the Rocky Mountain region of the United States.

        Kodiak Oil & Gas Corp. was incorporated (continued) in the Yukon Territory on September 28, 2001

Note 2—Basis of Presentation and Significant Accounting Policies

Basis of Presentation

        The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., a Colorado corporation. All significant inter-company balances and transactions have been eliminated in consolidation. The Company's business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars. The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting principles in the United States ("GAAP"). In the opinion of management, all adjustments, consisting primarily of normal recurring accruals that are considered necessary for a fair presentation of the consolidated financial information, have been included.

Use of Estimates in the Preparation of Financial Statements

        The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and gas reserves; (2) cash flow estimates used in ceiling test of oil and natural gas properties; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business combinations; (6) accrued revenue and related receivables; (7) valuation of commodity derivative instruments; (8) accrued liabilities; (9) valuation of share-based payments and (10) income taxes. Although management believes these estimates are reasonable, actual results could differ from these estimates. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions the Company believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes its estimates are reasonable.

Reclassifications

        Certain prior period balances were reclassified in order to conform to the current year presentation. Such reclassifications had no impact on net income, statements of cash flows, working capital or equity previously reported.

Cash and Cash Equivalents

        Cash and cash equivalents consist of all highly liquid investments that are readily convertible into cash and have original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value due to the short-term nature of these instruments.

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        As of December 31, 2011, the Company had approximately $70.1 million in a money market account with its bank. The money market account is limited to six withdrawals per month; however, there are no other redemption restrictions. Therefore, the Company classified the entire balance as Cash and Cash Equivalents at December 31, 2011.

Cash Held In Escrow

        Cash held in escrow consists of approximately $704.0 million deposited into third-party escrow accounts. On November 14, 2011, pursuant to the purchase and sale agreements for the January 2012 Acquisition, the Company deposited $30.0 million into escrow, which was released from escrow on January 10, 2012 and credited toward the purchase price of the January 2012 Acquisition. Additionally, on November 23, 2011, the Company deposited approximately $674.0 million into escrow, which consisted of the net proceeds from the Company's November 2011 Senior Note offering, together with cash of the Company. On January 10, 2012, all of the funds being held in such escrow accounts at December 31, 2011, were released and used to fund the purchase price of the January 2012 Acquisition, repay all borrowings under the Company's second lien credit agreement and general corporate purposes. The amount of cash held in escrow used to fund the purchase price of the January 2012 Acquisition and repay all borrowings under the Company's second lien credit agreement of $691.8 million was classified as a non-current asset and the remaining $12.2 million of cash held in escrow used for general corporate purposes was classified as a current asset in the consolidated balance sheets.

Accounts Receivable

        The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables in 2011, 2010, or 2009.

Concentration of Credit Risk

        The Company's cash and cash equivalents and cash held in escrow are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company often has balances in excess of the federally insured limits.

        The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

        The Company's commodity derivative contracts are currently with three counterparties. The counterparties to the derivative instruments are highly rated entities with corporate ratings at or exceeding A- and A2 classifications by Standard & Poor's and Moody's, respectively.

Significant Customers

        During the year ended December 31, 2011, over 63% of the Company's production was sold to three customers. However, the Company does not believe that the loss of a single purchaser, including these three, would materially affect the Company's business because there are numerous other purchasers in the area in which the Company sells its production. For the years ended December 31, 2011, 2010 and 2009 purchases by the following companies exceeded 10% of the total oil and gas revenues of the company.

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  For the Years Ended December 31,  
 
  2011   2010   2009  

Customer A

    27%       0%       0%  

Customer B

    25%     75%     55%  

Customer C

    11%       0%       0%  

Customer D

      4%       9%     16%  

Inventory, Prepaid Expenses and Other

        Included in inventory, prepaid expenses and other are deposits made on orders of tubular goods required for the Company's drilling program. As of December 31, 2011, there was approximately $9.4 million in deposits on tubular goods made and recorded. As of December 31, 2011, the Company estimates that an additional $9.4 million will be paid to complete the purchase and the deposits would be subject to forfeit if the purchases are not completed. The cost basis of the tubular goods is depreciated as a component of oil and gas properties once the inventory is used in drilling operations. The Company records tubular goods inventory at the lower of cost or market value. Inventory, prepaid expenses, and other are comprised of the following (in thousands):

 
  For the Years Ended December 31,  
 
  2011   2010  

Well equipment inventory

  $ 12,700   $ 9,741  

Deposit on tubular goods

    9,392     7,600  

Crude oil inventory

    706     636  

Prepaid expenses

    1,496     235  
           

  $ 24,294   $ 18,212  
           

Oil and Gas Properties

        The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

        Depletion of capitalized costs of oil and gas properties is computed using the units-of-production method based upon estimated proved oil and gas reserves as determined by the Company's engineers and prepared by independent petroleum engineers. For this purpose, Kodiak converts its petroleum products and reserves to a common unit of measure. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Costs included in the depletion base to be amortized include (a) all proved capitalized costs, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

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        Estimated reserve quantities and future net cash flows have the most significant impact on the Company. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company's proved properties. Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. For additional discussion on the process used to estimate oil and gas quantities please refer to Note 15—Supplemental Oil and Gas Reserve Information (Unaudited).

        Effective December 31, 2009, the depletion is calculated using proved reserves based on a twelve month arithmetic average of the oil and natural gas prices in effect on the first of each month. For all periods prior to December 31, 2009, the depletion was calculated using proved reserves valued at the applicable period-end oil and natural gas prices.

Impairment of Proved Oil and Gas Properties

        Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized. Effective December 31, 2009, the present value of estimated future net revenues was computed by applying prices based on a twelve month arithmetic average of the oil and natural gas prices in effect on the first of each month, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. For all periods prior to December 31, 2009, the ceiling test was calculated using proved reserves valued at the applicable period-end oil and natural gas prices.

        There were no impairment charges recognized for the years ended December 31, 2011, 2010 and 2009.

Unproved Oil and Gas Properties

        Unproved property costs not subject to amortization consist primarily of leasehold costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Interest costs related to significant unproved properties that are currently undergoing the activities necessary to get them ready for their intended use are capitalized to oil and gas properties. The Company's unproved properties are evaluated quarterly for the possibility of potential impairment. For the years ended December 31, 2011, 2010 and 2009 no impairment was recorded.

Wells in Progress

        Wells in progress at December 31, 2011 and December 31, 2010, represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then transferred to proved property when the wells are completed and first production commences. The costs then become subject to depletion and the ceiling test calculation in future periods. At December 31, 2011, the Company had 25 wells in progress in the Williston Basin, none of which were classified as such more than one year.

Equipment and Facilities

        Equipment and facilities are recorded at cost. Depreciation is recorded using the straight-line method over the estimated useful lives of the related assets, ranging from one to fifteen years.

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Property and Equipment

        Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment, and five years for office equipment and vehicles. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Deferred Financing Costs

        Deferred financing costs include origination, legal, engineering, and other fees incurred to issue the debt in connection with the Company's credit facilities and Senior Notes. Deferred financing costs related to the Company's Senior Notes are amortized to interest expense using the effective interest method over the term of the debt. Deferred financing costs related to the credit facilities are amortized to interest expense on a straight-line basis over the respective borrowing term.

Commodity Derivative Instruments

        The Company has entered into commodity derivative instruments, primarily utilizing swaps or "no premium" collars to reduce the effect of price changes on a portion of our future oil production. The Company's commodity derivative instruments are measured at fair value and are included in the accompanying balance sheets as commodity price risk management assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of income. The Company's valuation estimate takes into consideration the counterparties' credit worthiness, the Company's credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit-price for each derivative asset or liability under a market place participant's view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments. For additional discussion on commodity derivative instruments please refer to Note 6—Commodity Derivative Instruments.

Fair Value of Financial Instruments

        The Company's financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above) and long-term debt. The carrying values of cash and cash equivalents, accounts receivable and accounts payable are representative of their fair values due to their short-term maturities. The carrying amount of the Company's credit facility approximates fair value as it bears interest at variable rates over the term of the loan. The Company's second lien credit agreement and the Senior Notes are recorded at cost and the fair value is disclosed in Note 8—Fair Value Measurements. Considerable judgment is required to develop estimates of fair value. The estimates provided are not necessarily indicative of the amounts the Company would realize upon the sale or refinancing of such instruments.

Asset Retirement Obligation

        The Company recognizes estimated liabilities for future costs associated with the abandonment of its oil and gas properties. A liability for the fair value of an asset retirement obligation and corresponding increase to the carrying value of the related long-lived asset are recorded at the time the Company makes the decision to complete the well or a well is acquired. For additional discussion on asset retirement obligations please refer to Note 7—Asset Retirement Obligations.

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Revenue Recognition

        The Company recognizes revenues from the sale of crude oil and natural gas using the sales method of accounting. Revenues from the sale of crude oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. Additionally, there were no material imbalances at December 31, 2011, and December 31, 2010.

Share Based Payments

        At December 31, 2011, the Company has a stock-based compensation plan that includes restricted stock shares, restricted stock units ("RSUs"), performance awards ("PAs"), stock awards, and stock options issued to employees, officers and directors as more fully described in Note 11—Shared-Based Payments. The Company records expense associated with the fair value of stock-based compensation in accordance with ASC 718, Stock Based Compensation. The Company records compensation expense associated with the issuance of restricted stock shares and RSUs based on the estimated fair value of these awards determined at the time of grant. The PAs are payable in cash, except the Company may, in its discretion, determine to pay out the PAs on the vesting date through the issuance of shares of the Company's common stock. Consequently, as the remaining PAs will likely be settled in cash, a liability is recorded and remeasured at each quarter.

Income Taxes

        Deferred income tax assets and liabilities are recognized for the future income tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective income tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in income tax rates is recognized in income in the period that includes the enactment date. The measurement of deferred income tax assets is reduced, if necessary, by a valuation allowance if management believes that it is more likely than not that some portion or all of the net deferred tax assets will not be fully realized on future income tax returns. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment.

        The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.

Recent Accounting Pronouncements

        In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update may require certain additional disclosures related to fair value measurements. The Company does not expect the adoption of this update will materially impact its financial statement disclosures.

        Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

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Note 3—Oil and Gas Properties

        The Company's oil and gas properties are entirely within the United States. The net capitalized costs related to the Company's oil and gas producing activities were as follows (in thousands):

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Proved oil and gas properties

  $ 598,065   $ 205,360   $ 123,259  

Unproved oil and gas properties(1)

    263,462     107,254     12,068  

Wells in progress(2)

    78,505     21,418     2,691  

Equipment and facilities

    11,186     2,429      
               

Total capitalized costs

  $ 951,218   $ 336,461   $ 138,018  

Accumulated depletion, depreciation, amortization, and accretion

    (135,586 )   (103,799 )   (95,782 )
               

Net capitalized costs(3)

  $ 815,632   $ 232,662   $ 42,236  
               
(1)
Unproved oil and gas properties represent unevaluated costs the Company excludes from the amortization base until proved reserves are established or impairment is determined. The Company estimates that the remaining costs will be evaluated within 3 to 5 years.

(2)
Costs from wells in progress are excluded from the amortization base until production commences.

(3)
Includes capitalized interest of $8.4 million, $470,000, and $0 for the years ended December 31, 2011, 2010, and 2009, respectively.

        The following table presents information regarding the Company's net costs incurred in oil and natural gas property acquisition, exploration and development activities (in thousands):

 
  For the Years Ended December 31,  
 
  2011   2010   2009  

Property Acquisition costs:

                   

Proved

  $ 152,538   $ 33,539   $  

Unproved

    182,878     95,572     463  

Exploration costs

        14,821     5  

Development costs

    274,293     52,081     26,903  
               

Total

  $ 609,709   $ 196,013   $ 27,371  
               

Total excluding asset retirement obligation

  $ 608,102   $ 195,164   $ 27,193  
               

        Depletion expense related to the proved properties per equivalent BOE of production for the years ended December 31, 2011, 2010 and 2009 were $22.40, $17.92 and $14.40, respectively.

        The following table sets forth a summary of oil and gas property costs, which substantially consists of acquisition costs, not being amortized as of December 31, 2011 by the year in which such costs were incurred (in thousands):

 
  Unproved
Additions by Year
 

Prior

    7,229  

2009

    83  

2010

    75,071  

2011

    181,079  
       

Total

  $ 263,462  
       

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Note 4—Acquisitions and Divestitures

January 2012 Acquisition

        On January 10, 2012, ("Closing Date") the Company acquired two separate private, unaffiliated oil and gas company's ("Sellers") interests in approximately 50,000 net acres of Williston Basin leaseholds, and related producing properties located primarily in McKenzie and Williams Counties, North Dakota along with various other related rights, permits, contracts, equipment and other assets, including the assignment and assumption of a drilling rig contract (the "January 2012 Acquired Properties") for a combination of cash and stock. The Seller received 5.1 million shares of Kodiak's common stock valued at approximately $49.8 million and cash consideration of approximately $588.4 million. The effective date for the acquisition was September 1, 2011, with purchase price adjustments calculated at the Closing Date. The acquisition provided strategic additions adjacent to the Company's core project area. Pursuant to the Purchase and Sale Agreements, the Company deposited $30.0 million into escrow in November 2011, which was credited to the purchase price at the closing of the acquisition. The $30.0 million deposit is recorded on the balance sheet under long term cash held in escrow. The January 2012 Acquired Properties contributed no revenue to Kodiak for the year ended December 31, 2011. Transaction costs related to the acquisition incurred through December 31, 2011 were approximately $210,000 and are recorded in the statement of operations within the general and administrative expenses line item. The Company estimates an additional $40,000 of transaction costs will be incurred in the first quarter 2012. No material costs were incurred for the issuance of the 5.1 million shares of common stock.

        The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of January 10, 2012. Management has not had the opportunity to complete its assessment of the fair values of assets acquired and liabilities assumed. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision, which may be material, as the Company continues to evaluate the fair value of the acquisition (in thousands):

Preliminary Purchase Price
  January 10, 2012  

Consideration Given

       

Cash from Senior Notes

  $ 588,420  

Kodiak Oil & Gas Corp. Common Stock (5,055,612 Shares)

    49,798 *
       

Total consideration given

  $ 638,218  
       

Preliminary Allocation of Purchase Price

       

Proved oil and gas properties

  $ 292,185  

Unproved oil and gas properties

    311,068  

Wells in progress

    25,745  

Equipment and facilities

    12,615  
       

Total fair value of oil and gas properties acquired

    641,613  

Working capital

 
$

(2,595

)

Asset retirement obligation

    (800 )
       

Fair value of net assets acquired

  $ 638,218  
       

Working capital acquired was estimated as follows:

       

Accounts receivable

    2,000  

Prepaid completion costs

    465  

Crude oil inventory

    540  

Accrued liabilities

    (5,600 )
       

Total working capital

  $ (2,595 )
       
*
The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of January 10, 2012. (5,055,612 × $9.85)

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October 28, 2011 Acquisition

        On October 28, 2011, ("Closing Date") the Company acquired a private, unaffiliated oil and gas company's ("Seller") interests in approximately 13,400 net acres of Williston Basin leaseholds, and related producing properties located primarily in Williams County, North Dakota along with various other related rights, permits, contracts, equipment and other assets (the "October 2011 Acquired Properties"). The Seller received cash consideration of approximately $248.2 million and the effective date was August 1, 2011, with purchase price adjustments calculated at the Closing Date. The total purchase included approximately $245.5 million related to the acquisition of the properties and approximately $3.3 million related to the assumption of certain working capital items. The acquisition provided strategic additions adjacent to the Company's core project area. The October 2011 Acquired Properties contributed revenue of $6.2 million to Kodiak for the year ended December 31, 2011. Transaction costs related to the acquisition incurred were approximately $200,000 and are recorded in the statement of operations within the general and administrative expenses line item.

        The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of October 28, 2011. In February 2012, the Company completed the transactions post-closing settlement. The following table summarizes the preliminary purchase price and the preliminary estimated values of assets acquired and liabilities assumed and is subject to revision as the Company continues to evaluate the fair value of the acquisition (in thousands):

Preliminary Purchase Price
  October 28, 2011  

Consideration Given

       

Cash

  $ 248,213  
       

Total consideration given

  $ 248,213  
       

Preliminary Allocation of Purchase Price

       

Proved oil and gas properties

  $ 118,868  

Unproved oil and gas properties

    90,161  

Wells in progress

    25,720  

Equipment and facilities

    5,150  
       

Total fair value of oil and gas properties acquired

    239,899  

Working capital

 
$

8,552
 

Asset retirement obligation

    (238 )
       

Fair value of net assets acquired

  $ 248,213  
       

Working capital acquired was estimated as follows:

       

Accounts receivable

    10,260  

Prepaid drilling costs

    755  

Crude oil inventory

    190  

Well equipment inventory

    1,324  

Accrued liabilities

    (1,247 )

Suspense payable

    (2,730 )
       

Total working capital

  $ 8,552  
       

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June 30, 2011 Acquisition

        On June 30, 2011, ("Closing Date") the Company acquired a private, unaffiliated oil and gas company's ("Seller") interests in approximately 25,000 net acres of Williston Basin leaseholds and related producing properties located in McKenzie County, North Dakota along with various other related rights, permits, contracts, equipment and other assets (the "June 2011 Acquired Properties") for a combination of cash and stock. The Seller received 2.5 million shares of Kodiak's common stock valued at approximately $14.4 million and cash consideration of approximately $71.5 million. The effective date for the acquisition was April 1, 2011, with purchase price adjustments calculated at the Closing Date. The acquisition provided strategic additions to the Company's core positions in Koala, Smokey and Grizzly Project areas. The June 2011 Acquired Properties contributed revenue of $1.4 million to Kodiak for the year ended December 31, 2011. Transaction costs related to the acquisition were approximately $265,000, and are recorded in the statement of operations within the general and administrative expenses line item. Costs of $85,000 for issuing and registering with the SEC for the resale of 2.5 million shares of common stock were charged to common stock.

        The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of June 30, 2011. The transaction's final settlement was completed in September 2011 resulting in no material changes. As a result there were no changes from the Company's initial evaluation of the fair values of the net assets acquired in the acquisition or purchase price. The following table summarizes the purchase price and final allocation of the fair value of assets acquired and liabilities assumed (in thousands):

Purchase Price
  June 30, 2011  

Consideration Given

       

Cash from credit facilities

  $ 71,506  

Kodiak Oil & Gas Corp. Common Stock (2,500,000 Shares)

    14,425 *
       

Total consideration given

  $ 85,931  
       

Allocation of Purchase Price

       

Proved oil and gas properties

  $ 7,950  

Unproved oil and gas properties

    77,804  
       

Total fair value of oil and gas properties acquired

    85,754  

Working capital

 
$

235
 

Asset retirement obligation

    (58 )
       

Fair value of net assets acquired

  $ 85,931  
       

Working capital acquired was estimated as follows:

       

Accounts receivable

    325  

Crude oil inventory

    57  

Suspense payable

    (12 )

Accrued liabilities

    (135 )
       

Total working capital

  $ 235  
       
*
The fair value of the consideration attributed to the Common Stock under ASC 805 was based on the Company's closing stock price on the measurement date of June 30, 2011. (2,500,000 × $5.77)

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November 30, 2010 Acquisition

        On November 30, 2010, ("Closing Date") the Company acquired a private, unaffiliated oil and gas company's interests in approximately 14,500 net acres of Williston Basin leaseholds and related producing properties primarily located in McKenzie County, North Dakota (the "2010 Acquired Properties") for total consideration of $108.6 million. The effective date for the acquisition was August 1, 2010, with purchase price adjustments calculated at the Closing Date. The acquisition provided contiguous leaseholds with approved drilling permits near the Company's existing acreage position.

        The acquisition is accounted for using the acquisition method under ASC 805, Business Combinations, which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date of November 30, 2010. The transaction's final settlement was completed in April 2011 resulting in no material changes. As a result there were no changes from the Company's initial evaluation of the fair values of the net assets acquired in the acquisition or purchase price. The following table summarizes the purchase price and final fair value of assets acquired and liabilities assumed (in thousands):

Purchase Price
  November 30, 2010  

Consideration Given

       

Cash

  $ 108,649  
       

Total consideration given

  $ 108,649  
       

Allocation of Purchase Price

       

Proved oil and gas properties

  $ 32,232  

Unproved oil and gas properties

    77,193  
       

Total fair value of oil and gas properties acquired

    109,425  

Working capital

 
$

(541

)

Asset retirement obligation

    (235 )
       

Fair value of net assets acquired

  $ 108,649  
       

Working capital acquired was estimated as follows:

       

Accounts receivable

    269  

Crude oil inventory

    63  

Accrued liabilities

    (873 )
       

Total working capital

  $ (541 )
       

Pro Forma Financial Information

        The following unaudited pro forma financial information represents the combined results for the Company and the January 2012 Acquired Properties, October 2011 Acquired Properties, June 2011 Acquired Properties, and the November 2010 Acquired Properties for the years ended December 31, 2011 and 2010 as if the acquisitions had occurred on January 1, 2010 (in thousands, except per share data). For purposes of the pro forma it was assumed that the 8.125% Senior Notes were issued on January 1, 2010 and that the stand-by bridge was not utilized. The pro forma information includes the effects of adjustments for depletion, depreciation, amortization and accretion expense of $29.6 million and $10.4 million and amortization of financing costs of $1.6 million and $1.6 million for the years ended December 31, 2011 and 2010, respectively. For the year ended December 31, 2011, there was a pro forma adjustment of $4.0 million reducing interest expense. For the year ended December 31, 2010, there was a pro forma adjustment of $857,000 to record interest expense. Additionally, for the year

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ended December 31, 2011, there was a pro forma adjustment of $11.5 million to reduce interest expense related to the stand-by bridge financing. The pro forma financial information includes total capitalization of interest expense of $53.7 million and $52.8 million for the years ended December 31, 2011 and 2010, respectively. The pro forma results do not include any cost savings or other synergies that may result from the acquisitions or any estimated costs that have been or will be incurred by the Company to integrate the properties acquired. The pro forma results are not necessarily indicative of what actually would have occurred if the acquisitions had been completed as of the beginning of the period, nor are they necessarily indicative of future results.

 
  For the Years Ended December 31,  
 
  2011   2010  

Operating revenues

  $ 187,842   $ 45,400  
           

Net income (loss)

    43,660     (3,730 )
           

Net income (loss) per common share

             

Basic

  $ 0.21   $ (0.03 )
           

Diluted

  $ 0.21   $ (0.03 )
           

Divestitures

        In December 2011, the Company completed a sale of its interest in 5,266 undeveloped net acres all located in Wyoming for total cash consideration of $1.1 million. Additionally, Kodiak retained an overriding royalty interest in the leases conveyed. No gain or loss was recognized on the sale and the proceeds reduced unproved property acquisition costs and the full cost pool.

        In April 2011, the Company completed two separate sales of its interest in operated and non-operated wells, related surface equipment, and 3,046 undeveloped net acres all located in Wyoming for total cash consideration of $2.1 million. Kodiak was relieved of all reclamation liabilities associated with the producing properties. As a result of the divestiture, the Company's asset retirement obligation decreased by $610,000. Additionally, Kodiak retained an overriding royalty interest in certain leases conveyed. No gain or loss was recognized on the sale and the proceeds reduced the full cost pool.

Note 5—Long-Term Debt

        As of the dates indicated the Company's long-term debt consisted of the following (in thousands):

 
  At December 31, 2011  
 
  2011   2010  

Credit facility due October 2016

  $   $  

Second lien credit agreement due April 2017

    100,000     40,000  

8.125% Senior Notes due December 2019

    650,000      
           

Total Long-Term Debt

  $ 750,000   $ 40,000  

Less: Current Portion of Long Term Debt

         
           

Total Long-Term Debt, Net of Current Portion

  $ 750,000   $ 40,000