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Kodiak Oil 10-K 2010

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

Table of Contents

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, 2009

Commission file number: 001-32920



GRAPHIC

(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   NYSE Amex

         Securities registered pursuant to Section 12(g) of the Act:

Title of Each Class
N/A

         Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o    No ý

         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 o    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 Form 10-K. ý

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

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

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

         At June 30, 2009, the aggregate market value of the registrant's Common Stock held by non-affiliates of the registrant was approximately $114,155,080.

         The number of shares of the registrant's Common Stock outstanding as of March 10, 2010, was 118,879,931.

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 30, 2010, in connection with the registrant's 2010 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

    2  

PART I

   
4
 
 

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

    4  
 

ITEM 1A. RISK FACTORS

    18  
 

ITEM 1B. UNRESOLVED STAFF COMMENTS

    30  
 

ITEM 3. LEGAL PROCEEDINGS

    30  
 

ITEM 4. RESERVED

    30  

PART II

   
31
 
 

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

    31  
 

ITEM 6. SELECTED CONSOLIDATED FINANCIAL INFORMATION

    39  
 

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

    41  
 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    52  
 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

    53  
 

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

    77  
 

ITEM 9A. CONTROLS AND PROCEDURES

    77  
 

ITEM 9B. OTHER INFORMATION

    80  

PART III

   
81
 
 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

    81  
 

ITEM 11. EXECUTIVE COMPENSATION

    81  
 

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

    81  
 

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

    81  
 

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

    81  

PART IV

   
82
 
 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

    82  

SIGNATURES

   
88
 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

        The statements contained in this annual report on Form 10-K that are not historical are "forward-looking statements," as that term is defined in Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), that involve a number of risks and uncertainties.

        These forward-looking statements include, among others, the following:

    our business and growth strategies;

    our oil and natural gas reserve estimates;

    our ability to successfully and economically explore for and develop oil and gas resources;

    our exploration and development drilling prospects, inventories, projects and programs;

    availability and costs of drilling rigs and field services;

    anticipated trends in our business;

    our future results of operations;

    our liquidity and ability to finance our exploration and development activities;

    market conditions in the oil and gas industry; and

    the impact of environmental and other governmental regulation.

        These statements may be found under "Risk Factors", "Management's Discussion and Analysis of Financial Condition and Results of Operation", "Business and Properties" and other sections of this annual report. Forward-looking statements are typically identified by use of terms such as "may", "will", "could", "should", "expect", "plan", "project", "intend", "anticipate", "believe", "estimate", "predict", "potential", "pursue", "target" or "continue", the negative of such terms or other comparable terminology, although some forward-looking statements may be expressed differently.

        The forward-looking statements contained in this annual report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this annual report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to a number of factors, including:

    unsuccessful drilling activities;

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

    financial losses and reduced earnings related to our commodity derivative agreements;

    failure to produce enough oil to satisfy our commodity derivative agreements;

    incorrect estimates of required capital expenditures;

    failure to obtain sufficient capital resources to fund our operations;

    incorrect estimates of our proved reserves;

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    inability to replace our reserves through exploration and development activities;

    termination fees related to drilling rig contracts;

    hazardous and risky drilling operations;

    a decline in oil or natural gas production or oil or natural gas prices;

    impact of environmental and other governmental regulation, including delays in obtaining permits; and

    effects of competition.

        You should also consider carefully the statements under "Risk Factors" and other sections of this annual report, which address additional factors that could cause our actual results to differ from those set forth in the forward-looking statements.

        All forward-looking statements speak only as of the date of this annual report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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PART I

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

Overview and Strategy

        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. Our oil and natural gas reserves and operations are primarily concentrated in two Rocky Mountain basins, the Williston Basin of North Dakota and Montana and the Green River Basin of Wyoming and Colorado. Kodiak's 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 portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential non-conventional and conventional oil and natural gas prospects that we have the opportunity to explore, drill and develop. Significant prospects in our portfolio currently include:

Williston Basin

    Williston Basin in Western North Dakota and Eastern Montana:  As of December 31, 2009, we owned an interest in approximately 98,000 gross acres and 60,000 net acres in this geologic basin. The primary targets within the Basin are the Mission Canyon, Bakken, Three Forks and Red River Formations, as well as other formations that produce in the Basin. Of this total acreage position 55,000, gross (35,000 net) acres are located on the Fort Berthold Indian Reservation ("FBIR") in Dunn and Mountrail Counties, North Dakota. During 2009, we incurred capital expenditures of approximately $26.5 million on the FBIR, largely related to the drilling and completion operations on this oil play where we have drilled a total of thirteen wells, of which eleven are completed at March 8, 2010, and have recently spud our fourteenth well. We are currently operating one drilling rig on our FBIR acreage and intend to utilize this rig for continued drilling on the FBIR acreage during 2010. We are in the process of taking delivery of a second operated rig, which we intend to move to Sheridan County, Montana and use to drill two wells targeting the Red River Formation. Upon the drilling of these wells, we intend to move the rig to McKenzie County, North Dakota where it will be utilized to drill wells targeting the Bakken before being moved to the FBIR by mid 2010.

Green River Basin / Big Horn Basin / Powder River Basin

    Vermillion Basin of Southwest Wyoming:  At December 31, 2009, we owned an interest in approximately 44,000 gross (9,200 net) acres in the Vermillion Basin. In the first quarter of 2008, we entered into an exploration and development agreement with Devon Energy Production Company, L.P. ("Devon"), a wholly owned subsidiary of Devon Energy Corp., as part of our strategy to develop our play in the Vermillion Basin. During 2009, Devon attempted completion on one of the wells that had been drilled in 2008. This completion was temporarily abandoned in early 2010 and it is anticipated that one of the wells that was drilled vertically into the Baxter Shale during 2008 will be reentered and horizontally drilled to test the productive interval within the Baxter Shale. Effective August 1, 2009, we amended our agreement with Devon to assign additional interest to Devon and to provide that we will be carried for our 25% working interest in anticipated expenditures for 2010 and will retain an approximate 25% working interest in the balance of the acreage.

    Other Basins within Wyoming:  We have identified other prospects within the Big Horn and Powder River Basins that we intend to continue to evaluate based upon economic conditions.

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        Our results of operations and financial condition are significantly affected by the success of our exploration activity, the resulting production, oil and natural gas commodity prices and the costs related to operating our properties. As is common with companies engaged in the exploration of early resource plays, our financial position and results of operations change significantly from period to period.

        The Company was incorporated as a company 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 certain financial information of the Company, including information on loss and total assets, see Item 6—"Selected Consolidated Financial Information."

Capital Budget

        Our Board of Directors has approved a capital expenditure budget of $60 million for 2010, the majority of which is allocated to oil and gas activities to exploit the Bakken and Three Forks formations in the Williston Basin of North Dakota and Montana. Of the total capital expenditure budget, the Company has allocated $43 million to the drilling and completion of 15 gross (9.5 net) Kodiak-operated wells in Dunn County, North Dakota, including the installation of associated surface facilities, $12 million for seven gross (2.0 net) non-operated wells in Dunn County, North Dakota, and $5 million for three gross and (1.3 net) operated wells in Sheridan County, Montana and McKenzie County, North Dakota. Kodiak's working interest (WI) ranges from 35% to 100% in the operated 2010 drilling program, providing flexibility within the budget in identifying suitable well locations and in the timing and size of capital investment.

        The 2010 capital expenditure budget, both as to amount and allocation, is subject to 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. If we identify acreage that meets our strategic requirements, we may re-allocate our capital expenditure budget to permit us to complete a potential acreage acquisition. Alternatively, depending on the availability and terms of capital resources that may be available to us, we may increase our capital expenditure budget to allow us to acquire additional acreage. We expect to fund our capital budget primarily from cash on hand, anticipated cash flow from operations and borrowings under a potential reserve-based revolving line of credit that we anticipate will be available to us in the second quarter of 2010. If our existing and potential sources of liquidity are not sufficient to undertake our planned or revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties, sell interest in one or more of our properties or sell common shares. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our operating capital requirements. If we are 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, and we would be unable to implement our original exploration and drilling program.

Drilling and Completion Operations in Dunn County, North Dakota

        As of March 8, 2010, we have drilled thirteen wells and completed eleven wells in Dunn County, North Dakota. Of the eleven wells completed to date, nine wells were placed on production by year-end 2009. All of the wells were drilled to an approximate vertical depth of 10,300 feet. We tested

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the productive Bakken interval that is positioned between the upper and lower Bakken shales, which are the source rock for the oil. Of the nine completed wells in 2009, four were drilled with horizontal laterals of approximately 8,500 feet to 10,000 feet. The remaining five wells were drilled with shorter horizontal laterals between 4,200 feet and 6,600 feet.

        During 2010, we anticipate participating in approximately 22 gross wells, 15 of which will be operated by us and seven of which will not be operated by us. Of these 22 gross wells we are scheduled to drill, we anticipate that three wells will utilize shorter laterals and 19 wells will utilize longer horizontal laterals approaching 10,000 feet.

        The following chart provides more detailed information regarding the wells that were drilled and completed in 2009 and the first quarter of 2010.


Kodiak Oil & Gas Corp. Drilling and Completion Activities

Longer Laterals (8,000' to 10,000')

Well
  WI / NRI
(%)
  Days to
TD*
  Length of
Lateral
  Completion
Date
  Number of
Stages
  IP 24-Hour
Test BOE/D
  First 30 Day
BOE
Production
  Status

TSB #16-8-7H

    37.5 / 30.5     28     8.995'   6/7/2009     15     1,856     23,874   Flowing well

TSB #14-33-28H

    50 /41     31     8,313'   8/3/2009     15     1,492     21,400   Flowing well

CE #1-22-10H

    55 /45     32     9,949'   10/18/2009     15     1,288     15,510   Flowing well

TB #16-15-16H

    60 /50     25     9,442'   12/7/2009     19     100     1,569   Waiting on pump

MC #13-34-28-2H

    57.5 /46.5     35     9,769'   Q210               Waiting completion

MC #13-34-28-1H

    57.5 /46.5         8,600' ** Q210               Drilling

TSB #14-21-33-16H

    50 /41                         Spud after MC Pad

TSB #14-21-33-15H

    50 /41                         Spud after MC Pad


Shorter Laterals (4,000' to 7,000')

MC #16-34-2H

    60 /49     41     4,169'   4/23/2009     8     711     9,155   On pump

MC #16-34H

    60 / 49     36     4,150'   5/4/2009     5     1,394     14,720   On pump

TSB #16-8-16H

    50 /41     31     4,465'   6/18/2009     5     811     12,758   Flowing well

TSB #14-33-6H

    50 /41     26     4,163'   8/24/2009     6     978     13,608   Flowing well

CE #1-22-23H

    60 /50     19     6,620'   10/18/2009     13     845     11,916   Flowing well

MC #16-3-11H

    60 /49     38     4,729'   2/12/2010     12     1,419       Flowing well

MC #16-3H

    60 /49     19     4,188'   3/2/2010     9     1,495       Flowing well

MC #13-34-3H

    60 /49     22     4,330'   Q210     11           Waiting completion

TSB #14-21-4H

    50 /41                         Spud after MC Pad

*
Includes running liner in the hole

**
Approximate length of lateral

2009 Common Share Offerings

        In May 2009, we entered into agreements to sell 9,600,000 shares of our common stock to certain institutional investors, in a non-brokered registered direct offering. The aggregate gross proceeds from the offering were $7,200,000. The Company paid approximately $108,000 in expenses related to the offering. The net proceeds were used principally for drilling and completion activities on our leases in Dunn and Mountrail Counties, North Dakota and for other general corporate activities.

        In October 2009, the Company issued 13,800,000 shares of common stock in a public offering for gross proceeds of $30,360,000. The Company paid approximately $1,721,000 in expenses related to the offering. The net proceeds are being used principally for drilling and completion activities on the Company's leases in the Williston Basin and for other general corporate activities.

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Property Acquisition and Exploration Activities

        In the Williston Basin, as of December 31, 2009, we owned an interest in approximately 98,000 gross acres and 60,000 net acres. The primary targets within the Basin are the Mission Canyon, Bakken, Three Forks and Red River Formations, as well as other formations that produce in the Basin. We owned approximately 55,000 gross acres and 35,000 net acres on the FBIR with most of these lands acquired in previous years. The majority of our lands in this prospect area are held in trust and are administered by the Bureau of Indian Affairs (BIA) on behalf of the individual members of the Three Affiliated Tribes Fort Berthold Indian Reservation. 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 two to four years remaining on the primary lease term of these leases. Approximately 30% of these lands are encompassed within federal operating units approved by the U.S. 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.

        Our acreage located in the Williston Basin outside of the FBIR is held primarily on the basis of fee and federal leases. These leases typically carry a primary term of three to ten years with landowner royalties of 12.5% to 18.5%. 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 lands located in Wyoming are also federal lands administered by the 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.

        In February 2008, we entered into an exploration agreement ("Devon Agreement") with Devon under which Devon earned a 50% working interest in our leasehold interests in the Vermillion Basin in exchange for, among other things, expenditures that approximate the cost of three horizontally drilled and completed wells. Effective August 1, 2009, we amended our agreement with Devon to assign additional interest to Devon and to provide that we will be carried for our 25% working interest in anticipated expenditures for 2010 and will retain an approximate 25% working interest in the balance of the acreage.

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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 December 31, 2009.

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

Green River Basin

                                     

Wyoming

    42,555     9,770     1,520     908     44,075     10,678  

Colorado

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

Williston Basin

                                     

Montana

    27,640     16,806     800     400     28,440     17,206  

North Dakota

    62,405     38,519     7,200     3,992     69,605     42,511  

Other Basins

                                     

Wyoming

    12,362     10,675     0     0     12,362     10,675  

Acreage Totals

    152,301     80,730     9,520     5,300     161,821     86,030  

(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.

        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. The following table sets forth the gross and net acres of undeveloped land subject to leases that will expire during the next three years and have no options for renewal or are not included in Federal units:

 
  Expiring Acreage  
Year Ending
  Gross   Net  

December 31, 2010

    27,930     16,714  

December 31, 2011

    6,471     3,570  

December 31, 2012

    29,295     17,096  
           
 

Total

    63,696     37,380  
           

        A majority of the acreage expiring in 2010 is located in an area where we currently do not have drilling activity planned. We believe this acreage can be re-leased on advantageous terms as these plans evolve with further geological data. All of our leases grant us the exclusive right to explore for and develop oil, natural gas and other hydrocarbons and minerals that may be produced from wells drilled on the leased property without any depth restrictions. Our federal leases in Wyoming and Colorado generally include restrictions on drilling during the period of November 15 to April 30. These restrictions are intended to protect big game winter habitat and do not restrict operations or maintenance of production facilities. In most cases, our natural gas prospects are within a reasonable distance of natural gas pipelines, therefore limiting the construction of gathering systems necessary to tie into existing lines. Our oil is transported mostly by trucks and, if available, pipelines.

Production, Average Sales Prices, and Production Costs

        For the year ended December 31, 2009, we earned revenues on oil production of $10.7 million and on natural gas production of $0.6 million and incurred $2.2 million in production costs for the year

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ended December 31, 2009. Our oil revenues are derived primarily from eighteen wells that we operate in the Williston Basin. Our gas production comes from sixteen wells in the Green River Basin, five of which we operate and eleven of which we have a non-operating economic interest, and from the natural gas associated with our oil wells in the Williston Basin. Sales volumes, prices received, and production costs are summarized in the following table:

 
  Fiscal Year ended December 31,  
 
  2009   2008   2007  

Sales Volume:

                   

Gas (Mcf)

    220,455     209,815     200,191  

Oil (Bbls)

    182,558     63,595     102,914  

Production volumes (BOE)

    219,300     98,564     136,279  

Price:

                   

Gas ($/Mcf)

  $ 2.84   $ 6.54   $ 5.26  

Oil ($/Bbls)

  $ 58.35   $ 84.86   $ 65.72  

Production costs ($/BOE):

                   
 

Lease operating expenses

  $ 4.25   $ 28.78   $ 6.87  
 

Production and property taxes

  $ 5.50   $ 6.54   $ 5.30  
 

Gathering, transportation & marketing

  $ 0.37   $ 0.99   $ 0.73  

Capital Expenditures

        Our net capital expenditures were approximately $27.3 million in 2009 compared to approximately $11.0 million incurred in 2008. Our 2010 planned capital expenditures budget is $60 million, the majority of which is allocated to oil and gas activities to develop the Bakken and Three Forks Formations in the Williston Basin. Of the total capital expenditure budget, the Company has allocated $43 million to the drilling and completion of 15 gross (9.5 net) Kodiak-operated wells in Dunn County, North Dakota, including the installation of associated surface facilities. Our working interest (WI) ranges from 55% to 100% in the operated 2010 drilling program, providing flexibility within the budget in identifying suitable well locations and in the timing and size of capital investment.

        Further included in our 2010 capital expenditure budget is an estimated $12 million allocated to non-operated drilling activity in the Company's Area of Mutual Interest (AMI) with another operator located in Dunn County, North Dakota. Kodiak anticipates that approximately seven gross (2.0 net) non-operated wells will be drilled within the AMI in 2010.

        We also anticipate drilling of three additional gross wells (1.3 net) on our other Williston Basin leasehold in McKenzie County, North Dakota where the Bakken Formation will be developed, and in Sheridan County, Montana where the productive potential of the Red River Formation will be evaluated. The estimated capital expenditures required by Kodiak for drilling these wells are expected to be $5 million.

        We had working capital of $28.3 million inclusive of cash and cash equivalents of $24.9 million as of December 31, 2009. Our working capital included $7.3 million of prepaid tubular goods, which we expect to use in our 2010 drilling program. As we use these prepaid tubular goods, the value of such goods are expensed and are applied to our shares of the drilling costs or are recovered from our drilling partners. While we cannot fully assess our capital expenditures or the timing of expenditures in the Vermillion Basin since we do not operate the properties, we anticipate that a well previously drilled vertically in 2008 will be reentered, drilled horizontally and completed during 2010. As a result of our amended agreement in this prospect area, we anticipate that our share of drilling and completion costs will be carried by the operator.

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        The following tables set forth our capital expenditures for the year ended December 31, 2009 and our capital expenditures budget for our principal properties in 2010. Net capital expenditures include both cash expenditures and accrued expenditures and are net of proceeds from divestitures.

Project Location
  2009 Net Capital
Expenditures
($000)
  2010 Budgeted
Net Capital
Expenditures
($000)
 

Williston Basin

             

Mission Canyon/Red River wells and related infrastructure

    83     1,122  

Bakken wells and related infrastructure

    26,450     57,100  

Acreage/Seismic

    277     2,000  
           

Total Williston Basin

  $ 26,810   $ 60,222  
           

Wyoming

             

Vermillion Basin wells and related infrastructure

  $ 472   $  

Acreage/Seismic

    89      
           

Total Wyoming

  $ 561   $  
           

Total All Areas

  $ 27,371   $ 60,222  
           

Drilling Activity

        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 drilled during the years ended December 31, 2009, 2008 and 2007. In addition, as of December 31, 2009, we have five gross (1.06 net) non-operated wells in progress and two gross (1.2 net) operated wells in progress.

 
  2009   2008   2007  
 
  Gross   Net   Gross   Net   Gross   Net  

Development wells, completed as:

                                     
 

Oil wells

                    2     1.0  
 

Gas wells

            1     0.1          
 

Non-Productive(1)

                    1     0.5  

Exploratory wells, completed as:

                                     
 

Oil wells

    9     4.8                  
 

Gas wells

                    3     2.8  
 

Non-Productive(1)

                    4     1.8  
                           

Total

    9     4.8     1     0.1     10     6.1  
                           

(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.

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 December 31, 2009, all of which are located in the Rocky

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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

    18     9.5             18     9.5  

Wyoming/Colorado

                                     
 

Gas wells

    5     4.7     11     4.0     16     8.7  
                           

Total

    23     14.2     11     4.0     34     18.2  
                           

Operations in the Williston Basin of Montana and North Dakota

Bakken and Three Forks Formations—Dunn and McKenzie Counties, North Dakota

        We have continued our exploration activity in Dunn County, North Dakota where the primary objective is the dolomitic, sandy interval between the two Bakken Shales at an approximate vertical depth of 10,300 feet, and the Three Forks Formation that is present immediately below the lower Bakken Shale. We have completed eleven wells on the FBIR to date. We intend to operate up to fifteen additional wells in the area during 2010 and intend to participate in another seven additional wells, in which we will have a non-operated interest. We anticipate that we will drill wells on 1,280, 640 or 320 acre drilling blocks. The 1,280 acre and 640 acre blocks will allow for drilling of nearly 10,000 foot laterals, while the 320 acre blocks will allow for drilling of approximate 4,500 foot laterals. We intend to drill some of the wells in the Three Forks formation as additional production data is being obtained from other operators who are currently producing or drilling wells in that formation. We plan to continue to evaluate the completion techniques used in these wells during the year and expect to further enhance our completion methods as more data becomes available.

        Kodiak has three wells (two producing) in McKenzie County producing from the Bakken Formation near the North Dakota and Montana state line. We plan to drill at least one additional well in the Bakken Formation on our acreage in McKenzie County in 2010.

Red River-Mission Canyon Play—Sheridan County, Montana and Divide County, North Dakota

        The primary producing objectives in this prospect area are the Mission Canyon and the Red River formations at approximate depths of 8,000 feet and 11,000 feet, respectively. Kodiak previously acquired approximately 18 square miles of 3-D seismic data which defined closure on two Red River prospects. We expect to drill two wells on these targets in 2010. We are also monitoring Bakken and Three Fork exploration efforts in this area and will continue to evaluate the productive potential of the hydrocarbon bearing formations.

Operations in Wyoming and Colorado

Vermillion Basin Deep—Baxter Shale and Frontier Sandstone

        Our primary leaseholdings in the Green River Basin are 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. As of December 31, 2009, we controlled approximately 44,000 gross (9,200 net) acres in the Vermilion Basin.

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        Devon commenced drilling operations in August 2008 and has drilled four wells to date. 2009 exploration efforts were focused on the Coyote Flats Federal Unit (CFU) located on the northern edge. The CFU #14-36 well was drilled to an approximate vertical depth of 15,300 feet and 4,800 feet horizontally. Production liner was run into the lateral well bore, and completion work on this well was temporarily abandoned in early 2010. While exploration plans for 2010 have not been completely identified it is anticipated that the HBU #1-4 well, which was drilled to a vertical depth of approximately 11,700 feet and where approximately 240 feet was cored in the target pay zones, will be reentered and a horizontal lateral will be drilled in the targeted Baxter interval.

Recent SEC Rule-Making Amendments

        The Securities and Exchange Commission ("SEC") adopted amendments designed to modernize the SEC oil and gas company reserves reporting requirements, effective for our year end December 31, 2009. The most significant amendments to the requirements included the following:

    Commodity Prices—Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.

    Disclosure of Unproved Reserves—Probable and possible reserves may be disclosed separately on a voluntary basis.

    Proved Undeveloped Reserve Guidelines—Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and the well from which the reserves are to be recovered is scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

    Reserves Estimation Using New Technologies—Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.

    Reserves Personnel and Estimation Process—Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

    Non-Traditional Resources—The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.

        We adopted the rules effective for our year end December 31, 2009, as required by the SEC.

Our Reserves

        All of our reserves are located within the continental United States. Netherland Sewell & Associates, Inc. ("NSAI"), our independent petroleum engineering consulting firm, prepared our estimated reserves as of December 31, 2009 and December 31, 2008. NSAI audited our estimated reserves as of December 31, 2007. We have been advised that NSAI's 2007 audit consisted primarily of substantive testing, whereby NSAI conducted a detailed review of all of our properties.

        The Company did not place any limitations on NSAI in the conduct of NSAI's audit. The Company is not aware of the actual percentage of the Company's reserves audited by NSAI. We are not aware of any assumptions provided by management that were relied upon by NSAI without testing. The 2007 audit engagement of NSAI was authorized by the Board of Directors. NSAI reported to the management of the Company.

        A reserves audit and a financial audit are separate activities with unique and different processes and results. As currently defined by the Society of Petroleum Engineers, a reserves audit should be of

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sufficient rigor to determine the appropriate reserves classification for all reserves in the property set evaluated and to clearly state the reserves classification system being utilized. In contrast, a financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

        NSAI prepared our estimated reserves as of December 31, 2009 and December 31, 2008. The reserve estimates as of December 31, 2007 were developed using geological and engineering data and interests and burdens information developed by the Company. 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, 2009 and 2008 included in Item 8. "Financial Statements and Supplementary Data" in this Form 10-K in conjunction with the following reserve estimates:

 
  As of December 31,  
 
  2009   2008  

Proved Developed Oil Reserves (Thousands of Barrels, or MBbls)

    1,170.4     344.4  

Proved Undeveloped Oil Reserves (MBbls)

    2,646.3      
           

Total Proved Oil Reserves (MBbls)

    3,816.7     344.4  
           

Proved Developed Gas Reserves (Million Cubic Feet, or MMcf)

    1,454.9     1,218.0  

Proved Undeveloped Gas Reserves (MMcf)

    2,393.6      
           

Total Proved Gas Reserves (MMcf)

    3,848.5     1,218.0  
           

Total Proved Gas Equivalents (Million Cubic Feet Equivalent, or MMcfe)(1)

    26,748.9     3,284.4  

Total Proved Oil Equivalents (Thousands of Barrels Equivalent, or MBOE)(1)

    4,458.2     547.4  

Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10%(2)(3)

  $ 39,062.8   $ 5,328.1  

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

(2)
We calculated the present value of estimated future net revenues as of December 31, 2009 using the 12 month arithmetic average first of month price January through December 31, 2009. The resulting price used as of December 31, 2009 was $3.60 per Mcf for natural gas and $51.81 per barrel of oil. As of December 31, 2008 we utilized the oil and natural gas prices that were received by each respective property as of that date. The year-end December 31, 2008 prices that we utilized were $3.76 per Mcf and $24.09 per barrel of oil. The effect of the new methodology on the reserves at December 31, 2009 was not material; however, there was a decrease in present value, discounted at 10% of future net cash flows of approximately $28.1 million as compared to the prior SEC year-end pricing methodology.

(3)
The Present Value of Estimated Future Net Revenues After Income Taxes, Discounted at 10%, is referred to as the "Standardized Measure." There is no tax effect in 2009 or 2008 as the tax basis in properties and net operating loss exceeds the future net revenues. See Supplemental Oil and Gas Reserve Information (Unaudited) following our audited financial statements for the years ended December 31, 2009 and 2008.

        The foregoing values for the 2009 oil and gas reserves are based on the average of the first-day-of-the-month price during the 12-month period ending December 31, 2009, which results in a natural gas price of $3.02 per MMBtu (Questar Rocky Mountains price) or $3.95 per MMBtu (Northern Ventura

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price) and a crude oil price of $61.08 per barrel (West Texas Intermediate price). The values for the 2008 reserves are based on the year end December 31, 2008 natural gas price of $4.49 per MMBtu (Questar Rocky Mountains price) or $5.88 per MMBtu (Northern Ventura price) and crude oil price of $41.00 per barrel (West Texas Intermediate price). All prices are then further adjusted for transportation, quality and basis differentials.

        The reserves at December 31, 2009 were estimated using the definitions in SEC Release No.33-8995 Modernization of Oil and Gas Reporting. We had no proved undeveloped reserves at December 31, 2008; thus, all proved undeveloped reserves are less than one year old. Additionally, as there were no proved undeveloped reserves in 2008, there were no conversions of proved undeveloped reserves to proved developed producing wells in 2009. All proved undeveloped reserves were added in 2009 in connection with drilling we and our partners completed. All proved undeveloped locations are within one spacing offset of proved locations. We do not have any reserves that would be classified as synthetic oil or synthetic gas.

Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used

        Our year-end reserve report is 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 provide to them. This information is reviewed by knowledgeable members of our company to ensure accuracy and completeness of the data prior to submission to NSAI. Upon analysis and evaluation of data provided, NSAI issues a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our Reserves Manager, our COO and our President for completeness of the data presented and reasonableness of the results obtained. Once all questions have been addressed, NSAI issues the final appraisal report, reflecting their conclusions.

        Our reserve estimates are prepared by NSAI. A letter which identifies the professional qualifications of the individual at NSAI who was responsible for overseeing the preparation of our reserve estimates as of December 31, 2009 has been filed as an addendum to Exhibit 99.1 to this report.

Technologies used to determine Proved Reserve Estimate

        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, 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.

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 becomes more available. Conversely, as commodity prices increase, drilling equipment may be in short supply from time to time.

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Commodity Price Environment

        Generally, the demand for and the price of natural gas increases during the colder winter months and decreases during the warmer summer months. Pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Crude oil and the demand for heating oil are also impacted by seasonal factors, with generally higher prices in the winter. Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.

        Our results of operations and financial condition are significantly affected by oil and natural gas commodity prices, which can fluctuate dramatically. Commodity prices are beyond our control and are difficult to predict. In February 2010, we entered into a financial hedge (commodity derivative agreement) in order to manage our commodity price risk and to provide a more predictable cash flow from operations. Our commodity derivative contract at March 8, 2010 is a 'no premium' collar that was placed with BP Corporation North America Inc.

Governmental Regulations and Environmental Laws

        Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, some states in which we may operate 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. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of wells. Failure to comply with any such rules and regulations can result in substantial penalties. 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. Although we believe we are currently in compliance with all applicable laws and regulations, we are unable to predict the future cost or impact of complying with such laws because such rules and regulations are frequently amended or reinterpreted. We may be required to make significant expenditures to comply with governmental laws and regulations, which could have a material adverse effect on our business, financial condition and results of operations.

        Our operations are subject to various types of regulation at the federal, state, tribal and local levels that:

    require certain permits for the drilling of wells, including permits to drill wells on federal lands and lands administered by the Bureau of Indian Affairs, which generally require a minimum of 60-120 days; and permits to drill wells on state and fee lands, which generally require a minimum of 30-60 days;

    mandate that we maintain bonding requirements in order to drill or operate wells; and

    regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, temporary storage tank operations, air emissions from flaring, compression, and 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 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 natural gas and oil 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

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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 effect of all these 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. Where our operations are located on federal lands, the timing and scope of development may be limited by the National Environmental Policy Act, or environmental or species protection laws and regulations. The regulatory burden on the oil and natural gas industry increases our costs of doing business and, consequently, affects our profitability. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with applicable environmental and conservation requirements.

        Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and we expect that this trend will continue. These laws and regulations:

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

    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.

        The 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 in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.

        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 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. 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.

        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.

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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, the National Historic Preservation Act and often their state, tribal or local counterparts. Projects can be denied or significantly modified to accommodate tribal burial sites, archeological sites or other historical sites. 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 land would result in "significant impact." For purposes of NEPA, "major federal action" can be something as basic as issuance of a required permit. For oil and gas operations on federal 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. 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. Any new or additional NEPA analysis could also result in significant changes.

        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 begin, and existing facilities may be required to incur capital costs in order to remain in compliance. 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.

        The Company has not incurred, and does not currently anticipate incurring, any material capital expenditures for environmental control facilities.

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, 2009, we employed sixteen full-time employees. None of our employees are subject to a collective bargaining agreement, and we consider our relations with our employees to be excellent.

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, free of charge, on our website 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

        Investing in shares of our common stock is highly speculative and involves a high degree of risk. In addition to the other information included in this Form 10-K, you should carefully consider the risks described below before purchasing shares of our common stock. 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 might lose all or part of your investment.

Risks Relating to the Company

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;

    pressure or irregularities in geological formations;

    shortages of or delays in obtaining equipment and qualified personnel;

    equipment failures or accidents;

    adverse weather conditions;

    reductions in oil and natural gas prices;

    land title problems; and

    limitations in the market for oil and natural gas.

        Any of these risks can cause substantial losses, including 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.

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

        In February 2010, we entered into a financial hedge (commodity derivative agreement) in order to manage our commodity price risk and to provide a more predictable cash flow from operations. Our commodity derivative contract at March 8, 2010 is a 'no premium' collar that was placed with BP Corporation North America Inc. We do not intend to designate our derivative instruments as hedges for accounting purposes. The fair value of our derivative instrument 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 instrument will be recognized in current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative 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

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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 reducing the volatility of our cash flows, and in certain circumstances may actually increase 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 the Company's 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.

If we place hedges on future production and encounter difficulties meeting that production, we may not realize the originally anticipated cash flows.

        To the extent that our oil production is less than the production required under the commodity derivative contracts that we have in place, our cash flow may be adversely affected if energy prices rise above the prices for the forward-looking sales. In this case, we would be required to make payments to the purchaser of the forward-looking sale equal to the difference between the current commodity price and that in the sales contract multiplied by the physical volume of the shortfall. There is the risk that production estimates could be inaccurate or that unanticipated problems could cause the production to be less than the amount anticipated, causing us to make payments to the purchasers pursuant to the terms of the commodity derivative contracts.

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

        We have historically incurred losses from operations during our history in the oil and natural gas business. As of December 31, 2009, we had a cumulative deficit of $106 million. While we have developed some of our properties, many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties. 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. In addition, should we be unable to continue as a going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included in this Form 10-K.

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

        This Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves. The December 31, 2009 reserve estimate was prepared by NSAI. 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 not assume that the present value of future net revenues referred to in this Form 10-K 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. 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.

The ongoing economic recession may have material adverse impacts on our business and financial condition that we currently cannot predict.

        The US and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Although we cannot predict the resulting impact of global economic conditions on our business, such economic conditions could materially adversely affect our business and financial condition.

        For example:

    the demand for oil and natural gas may decline due to deteriorating economic conditions, which could negatively impact the revenues, margins and profitability of our oil and natural gas business;

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    our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business, including for exploration or development of our reserves; or

    our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

We may incur termination fees related to two drilling rig contracts that we entered into in 2008 which could impair our working capital.

        During the second quarter of 2008, we entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 under a two-year agreement that provides for termination fees if termination occurs prior to the fourth quarter of 2010. The estimated termination fee for the first rig would have been approximately $3.5 million if we were to have terminated the rig at December 31, 2009. Under the terms of the drilling rig contract for the second rig (the "Second Rig Contract"), we were initially scheduled to take delivery of the second rig in February 2009 but, effective August 2009, we agreed with the contractor to amend the Second Rig Contract to defer such delivery in exchange for certain delay payments. Effective December 2009, we further amended the Second Rig Contract with the contractor, whereby we will take delivery of the second rig in the first quarter of 2010 and will no longer make delay payments. The maximum termination fee payable by us would be $5.1 million, against which all of the delay payments made would be applied in the form of a credit. While we intend to utilize both rigs in our drilling operations, if we are unable to maintain our planned drilling operations, we may be required to pay a termination fee to the contractors, which could impair our working capital.

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 coverage is prohibitively expensive. We do not carry business interruption insurance coverage. Our exploration, drilling and other activities are subject to risks such as:

    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;

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

    natural disasters and other environmental disturbances, which may increase in the event of ongoing patterns of adverse changes in weather or climate; and

    acts of terrorism.

        Losses and liabilities arising from uninsured and underinsured events, which could arise from even one catastrophic accident, could materially and adversely affect our business, results of operations and financial condition.

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We have limited control over activities in properties we do not operate, which could reduce our production and revenues and affect the timing and amounts of capital requirements.

        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:

    timing and amount of capital expenditures;

    expertise and financial resources; and

    inclusion of other participants.

Our operations in North Dakota, Montana and Wyoming could be adversely affected by poor weather conditions.

        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, our federal leases generally include restrictions on drilling during the period of November 15 to April 30. These restrictions are intended to protect big game winter habitat and not to restrict operations or maintenance of production facilities. To the extent that our exploration and drilling program on our federal leases cannot be completed during the period of May 1 through November 14, our drilling program may be delayed.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

        We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us in the future. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder access to oil and natural gas markets or delay production, if any, at our wells. The availability of a ready market for our future oil and natural gas production will depend on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Any significant change in our arrangements with gathering system or pipeline owners and operators or other market factors affecting the overall infrastructure facilities servicing our properties would adversely affect our ability to deliver the oil and natural gas we produce to markets in an efficient manner.

We depend on a limited number of customers for sales of our oil. We are exposed to credit risk if one or more of our significant customers becomes insolvent and fails to pay amounts owed to us. To the extent our customers cease to be creditworthy, our revenues could decline.

        During the year ended December 31, 2009, over 55% of our oil production was sold to one customer. We also sell our production to a number of other customers, and we believe that those customers, along with other purchasers, would purchase all or substantially all of our production in the

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event that our major customer curtailed its purchases. It is possible that one or more of our customers will become financially distressed and default on their obligations to the Company. Furthermore, bankruptcy of one or more of our customers, or some 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.

We rely on independent experts and technical or operational service providers over whom we may have limited control.

        We use independent contractors to provide us with technical assistance and services. We rely upon the owners and operators of rigs and drilling equipment, and upon providers of field services, to drill and develop our prospects to production. In addition, we rely upon the services of other third parties to explore or analyze our prospects to determine a method in which the prospects may be developed in a cost-effective manner. Our limited control over the activities and business practices of these providers, any inability on our part to maintain satisfactory commercial relationships with them or their failure to provide quality services could materially and adversely affect our business, results of operations and financial condition.

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. Generally, the leases we are a party to provide for a fixed term, but contain a provision that allows us to extend the term of the lease so long as we are producing oil or natural gas in quantities to meet the required payments under the lease. 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 oil and natural gas leases or 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.

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

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

Increases in interest rates could adversely affect our results of operations.

        Although we currently have no borrowings under a credit facility, if we borrow funds in the future, our credit facility would be subject to a floating interest rate which may vary in line with the movements in short-term interest rates. As a result, our interest expenses may increase significantly if short-term interest rates increase. To the extent that we rely on a credit facility, an increase in the interest rate under that facility would increase the borrowing cost of our outstanding debt.

Our officers and directors may become subject to conflicts of interest.

        Some of our directors and officers may also become directors, officers, contractors, shareholders or employees of other companies engaged in oil and natural gas exploration and development. To the extent that such other companies may participate in ventures in which we may participate, our directors may have a conflict of interest in negotiating and concluding terms respecting the extent of such participation. In the event that such a conflict of interest arises at a meeting of our directors, a director who has such a conflict will declare his interest and abstain from voting for or against the approval of such participation or such terms. In appropriate cases, we will establish a special committee of independent directors to review a matter in which several directors, or management, may have a conflict. From time to time, several companies may participate in the acquisition, exploration and development of oil and natural gas properties thereby allowing for their participation in larger programs, permitting involvement in a greater number of programs and reducing financial exposure in respect of any one program. A particular company may assign all or a portion of its interest in a particular program to another of these companies due to the financial position of the company making the assignment.

        In accordance with the laws of the Yukon Territory, our directors are required to act honestly, in good faith and in the best interests of our company. In determining whether or not we will participate or acquire an interest in a particular program, our officers will primarily consider the potential benefits to our company, the degree of risk to which we may be exposed and our financial position at the time.

We depend on a number of key personnel who would be difficult to replace.

        We are dependent upon the expertise of our management team, including our executive officers and other key employees. The loss of the services of our executive officers, or any other member of our management team, through incapacity or otherwise, would be costly to us and would require us to seek and retain other qualified personnel. Failure to find a suitable replacement for any member of our management team could negatively impact our ability to execute our strategy.

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Risks Relating to Our Industry

A substantial or extended decline in oil or natural gas prices could reduce our future revenue and earnings.

        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 sale of oil or natural gas.

        Our revenues and growth, and the carrying value of our oil and natural gas properties are substantially dependent on prevailing prices of oil and natural gas. Our ability to obtain additional capital on attractive terms is also substantially dependent upon oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control. These factors include changes in global supply and demand for oil and natural gas, economic conditions in the United States and Canada, the actions of OPEC, governmental regulation, the price and quantity of imports in foreign oil and natural gas-producing regions, political conditions, including embargoes in oil and natural gas-producing regions, the level of global oil and natural gas inventories, weather conditions, technological advances affecting energy consumption and the price and availability of alternate fuel sources. Any substantial and extended decline in the price of oil and natural gas would have an adverse effect on our business, financial condition and results of operations.

        Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for 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.

        Local, national and international economic conditions are beyond our control and may have a substantial adverse effect on our efforts. We cannot guard against the effects of these potential adverse conditions.

Oil and natural gas are commodities subject to price volatility based on many factors outside the control of producers, and low prices may make properties uneconomic for future production.

        Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices a producer may expect and its level of production depend on numerous factors beyond its control, such as:

    changes in global supply and demand for oil and natural gas;

    economic conditions in the United States and Canada;

    the actions of the Organization of Petroleum Exporting Countries, or OPEC;

    government regulation;

    the price and quantity of imports of foreign oil and natural gas;

    political conditions, including embargoes, in oil- and natural gas-producing regions;

    the level of global oil and natural gas inventories;

    weather conditions;

    technological advances affecting energy consumption; and

    the price and availability of alternative fuels.

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        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.

        To attempt to reduce our price risk, in 2010, we 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.

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. During 2009 and 2008, we recognized approximately $0 and $47.5 million, respectively, in ceiling test write-downs. 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 and local 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 and local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. 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 bonds;

    drilling permits;

    reports concerning operations;

    air quality, noise levels and related permits;

    spacing of wells;

    rights-of-way and easements;

    unitization and pooling of properties;

    gathering, transportation and marketing of oil and natural gas;

    taxation; and

    waste transport and disposal permits and requirements.

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        Failure to comply with these laws may result in the suspension or termination of operations and subject us to liabilities under 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.

The adoption of climate change and derivatives legislation by Congress may increase operating costs and reduce demand for the oil and natural gas we produce and could have an adverse impact on our ability to hedge risks associated with our business.

        In 2010, we implemented a strategy to hedge a portion of our crude oil and natural gas production. Congress is currently considering legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. Such legislation would establish an economy-wide cap on emissions of greenhouse gases ("GHG") in the United States and would require an overall reduction in GHG emissions by 2020. Most sources of GHG emissions would be required to obtain GHG emission "allowances" corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet the proposed legislation's overall emission reduction goals. As the number of GHG emission allowances declined each year, the cost or value of allowances would be expected to escalate significantly. The net effect of this legislation will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products and natural gas.

        Additionally, the proposed legislation contains provisions that would prohibit private energy commodity derivative and hedging transactions by expanding the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to energy commodities, including natural gas and oil, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under the proposed legislation, the CFTC's expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits should be applied consistently across all markets and participants. Although it is not possible at this time to predict whether or when Congress may act on derivatives and climate change legislation, any laws or regulations that may be adopted that subject us to additional capital or margin requirements relating to, or additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

Potential legislation related to "over-the-counter" derivatives could adversely impact our ability to execute our hedging strategy.

        In response to the role that "over-the-counter" derivatives are perceived to have played in the global financial crisis that began in 2008, Congress is currently drafting legislation to increase the regulation of the markets for these instruments, including legislation that would impose comprehensive regulation on the over-the-counter (OTC) derivatives marketplace. This legislation would subject swap dealers and major swap participants to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants and would provide the CFTC with authority to impose position limits in the OTC derivatives markets. These efforts may result, among other things, in legislation that would require us to clear our commodity derivatives through clearinghouses, and post cash collateral when market prices rise above the strike prices of our derivatives.

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        If this or similar legislation is promulgated, the cost of executing our hedging strategy could increase significantly, which could potentially result in an undesirable decrease in the amount of oil production we hedge. Increases in hedging costs and the need to post cash collateral would have an adverse effect on our business 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.

        Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which 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. In addition, these bills, if adopted, could establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and doing business.

Proposed legislation to eliminate or reduce certain federal income tax incentives and deductions available to oil and gas exploration and production companies could, if enacted into law, have a material adverse effect on our results of operations and cash flows.

        In April 2009, legislation was introduced to eliminate or reduce certain federal income tax incentives and deductions currently available to oil and gas exploration and production companies. The proposed amendments include the elimination or reduction of current deductions for intangible drilling and development costs, percentage depletion allowances and the manufacturing deduction for oil and gas properties. If some or all of these provisions are enacted into law, our effective tax rate and current income tax expense will increase, potentially significantly, which would reduce cash flows from operating activities and in turn reduce cash available for drilling and other exploration and development activities.

Exploration and drilling operations are subject to significant environmental regulation, including those related to climate and emission of "greenhouse gases," which may increase costs or limit our ability to develop our properties.

        We may encounter hazards incident to the exploration and development of oil and natural gas properties, such as accidental spills or leakage of petroleum liquids and other unforeseen conditions. We may be subject to liability for pollution and other damages due to hazards that we cannot insure against due to prohibitive premium costs or for other reasons. Governmental regulations relating to environmental matters could also increase the cost of doing business or require alteration or cessation of operations in some areas.

        Existing and possible future environmental legislation, regulations and actions, including those related to climate and emissions of "greenhouse gases," could give rise to additional expense, capital expenditures, restrictions and delays in our activities, the extent of which we cannot predict. Regulatory requirements and environmental standards are subject to constant evaluation and may be significantly increased, which could materially and adversely affect our business or our ability to develop our properties on an economically feasible basis. Before development and production can commence on

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any properties, we must obtain regulatory and environmental approvals. We cannot assure you that we will obtain such approvals on a timely basis or at all. The cost of compliance with changes in governmental regulations has the potential to reduce the profitability of our operations and preclude entirely the economic development of a specific property.

The oil and natural gas industry is subject to significant competition, which may increase costs or otherwise 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. Our ability to compete for oil and natural gas producing properties will be affected by the amount of funds available to us, information available to us and any standards established by us for the minimum projected return on investment. Our products will also face competition from alternative fuel sources and technologies.

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.

Risks Relating to Our Common Stock

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

        On July 14, 2008, we filed a shelf registration statement on Form S-3 (SEC file No. 333-152311), which was declared effective by the SEC on July 24, 2008. Under this shelf registration statement, we have raised funds and 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 pursuant to our effective shelf registration statements or otherwise, our existing stockholders' ownership will be diluted.

Our common stock has a limited trading history and has experienced price and volume volatility.

        Our common stock has been trading on the NYSE Amex since June 21, 2006. Prior to listing on the NYSE Amex, our common stock traded on the TSX Venture Exchange, or TSX-V, beginning September 28, 2001. 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:

    the breadth of our stockholder base and extent to which securities professionals follow our common stock;

    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;

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    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. Accordingly, investors may only see a return on their investment if the value of our securities appreciates.

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. In 2005, we issued 20,671,875 shares of our common stock for net proceeds of $17,879,673. In 2006, we issued 31,589,268 shares of our common stock for net proceeds of $83,209,451. In 2008, we issued 6,820,000 shares of our common stock for net proceeds of $17,471,488. In 2009 we issued 23,400,000 shares of our common stock for net proceeds of $35,731,122. Any further issuances of shares of our common stock from our treasury will result in immediate dilution to existing shareholders and may have an adverse effect on the value of their shareholdings.

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.    RESERVED

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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 since June 21, 2006 under the symbol "KOG". On March 10, 2010, there were 70 holders of record of our Common Stock.

 
  NYSE Amex  
Quarter Ended
  High   Low  

December 31, 2009

  $ 2.78   $ 2.03  

September 30, 2009

  $ 2.89   $ 0.70  

June 30, 2009

  $ 1.49   $ 0.33  

March 31, 2009

  $ 0.58   $ 0.16  

December 31, 2008

  $ 1.55   $ 0.29  

September 30, 2008

  $ 4.84   $ 1.11  

June 30, 2008

  $ 5.50   $ 1.57  

March 31, 2008

  $ 2.63   $ 1.56  

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 and other factors as our board may deem relevant at that time.

Securities Authorized for Issuance under Equity Compensation Plans

        In 2007 we adopted the 2007 Stock Incentive Plan (the "2007 Plan"), which replaced the Incentive Share Option Plan (the "Pre-existing Plan"). Under the 2007 Plan, stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards may be granted to any employee, consultant, independent contractor, director or officer of the Company. A total of 8,000,000 shares of common stock may be issued under the 2007 Plan, which includes shares issuable under the Pre-existing Plan pursuant to options outstanding as of the effective date of the 2007 Plan. No more than 8,000,000 shares may be used for stock issued pursuant to incentive stock options and the number of shares available for granting restricted stock and restricted stock units shall not exceed 1,000,000, subject to adjustment as defined in the 2007 Plan. We granted 1,150,000 stock options and had 2,721,999 stock options that were either cancelled or forfeited 2009. As of December 31, 2009, the Company has outstanding options to purchase 5,585,000 common shares at prices ranging from $0.36 to $6.26.

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Equity Compensation Plan Information as of December 31, 2009

Plan Category
  (a)
Number of
securities to be
issued upon
exercise of
outstanding
options,
warrants and
rights
  (b)
Weighted average
exercise price of
outstanding
options,
warrants and
rights
  (c)
Number of
securities
remaining
available for
future issuance
under equity
compensation
plans
(excluding
securities
reflected in
column (a))
 

Equity compensation plans approved by security holders

    5,585,000 (1) $ 2.36     2,392,000  

Equity compensation plans not approved by security holders

    N/A     N/A     N/A  

Total

    5,585,000 (1) $ 2.36     2,392,000  

(1)
Excludes 24,000 shares of restricted stock granted in 2008.

        As of December 31, 2009 and December 31, 2008, the number of shares available for granting of stock options under the Company's 2007 Plan was 2,392,000 and 431,501, respectively. During the fiscal years ended December 31, 2009 and December 31, 2008, the Company made no changes to the exercise price of outstanding options through cancellation and reissuance or otherwise. At December 31, 2009, certain officers and directors voluntarily terminated outstanding options to purchase an aggregate of 1,150,00 shares issued during 2007.

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, any dividends remitted to U.S. Holders, as defined below, will be subject to withholding tax. See "Canadian Federal Income Tax Considerations."

        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.

Material Income Tax Consequences

        A brief description of certain provisions of the tax treaty between Canada and the United States is included below, together with a brief outline of certain taxes, including withholding provisions, to which United States security holders are subject under existing laws and regulations of Canada and the United States. The consequences, if any, of provincial, state and local taxes are not considered.

        The following information is general and security holders should seek the advice of their own tax advisors, tax counsel or accountants with respect to the applicability or effect on their own individual circumstances of the matters referred to herein and of any provincial, state or local taxes.

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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.;

    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.

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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 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.

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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 foreign income 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 paid on common shares generally will not be eligible for the "dividends received deduction."

        For taxable years beginning before January 1, 2011, 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 the Company is QFC, but a U.S. Holder otherwise 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.

Disposition of Common Shares

        A U.S. Holder will recognize 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.

        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."

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        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

        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."

        Subject to specific rules, foreign taxes paid with respect to any distribution in respect of stock in a PFIC are generally eligible for the foreign tax credit. The rules relating to distributions by a PFIC and their eligibility for the foreign tax credit are complicated, and a U.S. Holder should consult with their own tax advisor regarding the availability of the foreign tax credit with respect to distributions by a PFIC.

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

Information Reporting; Backup Withholding Tax For Certain Payments

        Under U.S. federal income tax law and regulations, certain categories of U.S. Holders must file information returns with respect to their investment in, or involvement in, a foreign corporation. Penalties for failure to file certain of these information returns are substantial. U.S. Holders of common shares should consult with their own tax advisors regarding the requirements of filing information returns, and if applicable, any "mark-to-market election" or "QEF election" (each as defined below).

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        Payments made within the U.S., or by a U.S. payor or U.S. middleman, of dividends on, and proceeds arising from certain sales or other taxable dispositions of, common shares generally will be subject to information reporting and backup withholding tax, at the rate of 28%, 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, U.S. Holders that are corporations generally are excluded from these information reporting and backup withholding tax rules. 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 on a timely basis. Each U.S. Holder should consult its own tax advisor regarding the information reporting and backup withholding tax rules.

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 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 means all revenues less the cost of goods sold, 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 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.

        The Company does not believe that it was a PFIC for the tax year ended December 31, 2009, and based on current business plans and financial projections; the Company does not expect that it will be a

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PFIC for the tax year ending December 31, 2010. 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.

        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.

Sales of Unregistered Securities

        During the year ended December 31, 2009, we did not have any sale of securities in transactions that were not registered under the Securities Act of 1933, as amended.

Use of Proceeds

        On July 14, 2008, we filed a shelf registration statement on Form S-3 (SEC File No. 333-152311), which was declared effective by the SEC on July 24, 2008. Under this shelf registration statement, we have raised funds through public offerings of our common stock. In August 2008, the Company issued 6,820,000 shares of common stock in a public offering for gross proceeds of approximately $18.8 million. The Company paid approximately $1.3 million in commissions and expenses. In May 2009, the Company entered into agreements to sell 9,600,000 shares of our common stock to certain institutional investors, in a non-brokered registered direct offering. The aggregate gross proceeds from the offering were approximately $7.2 million. The Company paid approximately $108,000 in expenses related to this offering. In October 2009, the Company issued 13,800,000 shares of common stock in a public offering for gross proceeds of approximately $30.4 million. The Company paid approximately $1.7 million in expenses related to this offering. The net proceeds from these offerings has been and will be used principally for drilling and completion activities on the Company's leases in the Bakken and Three Forks oil play located on the Fort Berthold Indian Reservation and for other general corporate activities.

Issuer Purchases of Equity Securities

        During the fiscal year ended December 31, 2009, neither the Company nor any affiliated purchaser purchased any of the Company's equity securities.

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ITEM 6.    SELECTED CONSOLIDATED FINANCIAL INFORMATION

        The data set forth below should be read in conjunction with Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Financial Statements and Notes thereto appearing at Item 8 of this report. The selected statements of operations data for the years ended December 31, 2009, 2008, and 2007 and balance sheet data as of December 31, 2009 and 2008 set forth below have been derived from our audited financial statements included elsewhere in this Annual Report on Form 10-K. The selected statements of operations data for the years ended December 31, 2006 and December 31, 2005 and balance sheet data as of December 31, 2007, 2006 and 2005 set forth below have been derived from the audited financial statements for such years not included in this Annual Report on Form 10-K.

 
  For the Years Ended December 31,  
 
  2009   2008   2007   2006   2005  

Income Statement Data:

                               

Revenue

 
$

11,337,709
 
$

6,964,790
 
$

9,320,377
 
$

4,965,169
 
$

453,135
 

Cost and expenses, excluding impairment

    13,901,007     15,962,854     13,506,267     7,751,209     2,458,226  

Asset impairment

        47,500,000     34,000,000          

Net loss

    (2,563,298 )   (56,498,064 )   (38,185,890 )   (2,786,040 )   (2,005,091 )

Basic and diluted net loss per common share

  $ (0.02 ) $ (0.62 ) $ (0.44 ) $ (0.04 ) $ (0.05 )

Adjusted EBITDA (see below reconciliation)

  $ 4,012,692   $ (1,237,829 ) $ 2,680,565   $ 947,247   $ (1,210,248 )

(1)
We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization, (iv) impairment expense, (v) non-cash expenses relating to share based payments recognized under ASC Topic 718, (vi) pre-tax unrealized gains and losses on foreign currency and (vii) accretion of abandonment liability. See "Non GAAP Financial Measure" below for further discussion of this measure.

 
  For the Years Ended December 31,  
 
  2009   2008   2007   2006   2005  

Balance Sheet Data:

                               

Current assets

 
$

37,005,416
 
$

20,654,933
 
$

15,377,809
 
$

61,117,145
 
$

7,990,556
 

Property and equipment, net

    42,236,077     17,842,773     58,386,427     52,250,265     17,463,269  

Total assets

    79,683,024     39,016,479     74,331,321     113,773,614     25,790,316  

Current liabilities

    8,694,432     5,231,075     5,163,457     9,879,104     4,411,572  

Stockholders' equity

  $ 69,928,382   $ 32,998,224   $ 68,293,366   $ 103,644,815   $ 21,309,671  

Basic and diluted weighted-average common shares outstanding

    103,688,733     90,739,316     87,742,996     71,425,243     44,447,269  

        No dividends have been declared in any of the periods presented above.

Non-GAAP Financial Measure

        We use EBITDA, adjusted as described below and referred to in this Form 10-K as Adjusted EBITDA, as a supplemental measure of our performance and liquidity that is not required by, or presented in accordance with, GAAP. We define Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) impairment (v) non-cash

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expenses relating to share based payments recognized under ASC Topic 718, (vi) pre-tax unrealized gains and losses on foreign currency and (vii) accretion of abandonment liability. In evaluating our business, we consider Adjusted EBITDA as a key indicator of financial operating performance and as a measure of the ability to generate cash for operational activities and future capital expenditures.

        Adjusted EBITDA is not a Generally Accepted Accounting Principle ("GAAP") measure of performance. The Company uses this non-GAAP measure primarily to compare its performance with other companies in the industry that make a similar disclosure and as a measure of its current liquidity. The Company believes that this measure may also be useful to investors for the same purpose and for an indication of the Company's ability to generate cash flow at a level that can sustain or support our operations and capital investment program. Investors should not consider this measure in isolation or as a substitute for operating income or loss, cash flow from operations determined under GAAP, or any other measure for determining the Company's operating performance that is calculated in accordance with GAAP. In addition, because EBITDA is not a GAAP measure, it may not necessarily be comparable to similarly titled measures employed by other companies.

        In evaluating Adjusted EBITDA, you should be aware that it excludes expenses that we will incur in the future on a recurring basis. Adjusted EBITDA has limitations as an analytical tool, and you should not consider it in isolation. Some of its limitations are:

    it does not reflect non-cash costs of our stock incentive plans, which are an ongoing component of our employee compensation program; and

    although depletion, depreciation and amortization are non-cash charges, the assets being depleted, depreciated and amortized will often have to be replaced in the future, and Adjusted EBITDA does not reflect the cost or cash requirements for such replacements.

        We compensate for these limitations by relying primarily on our GAAP results and using Adjusted EBITDA only supplementally. The following table presents a reconciliation of our net income to our Adjusted EBITDA on a historical basis for each of the periods indicated:

 
  For the Years Ended December 31,  
 
  2009   2008   2007   2006   2005  

EBITDA Reconciliation:

                               

Net Loss

 
$

(2,563,298

)

$

(56,498,064

)

$

(38,185,890

)

$

(2,786,040

)

$

(2,005,091

)
 

Add back:

                               
   

Depreciation, depletion, amortization and accretion

    3,158,433     4,172,077     5,206,631     2,173,918     157,868  
   

Asset impairment

        47,500,000     34,000,000          
   

(Gain) / loss on foreign currency exchange

    (11,327 )   36,725     (792,467 )   32,008     95,864  
   

Stock based compensation expense

    3,428,884     3,551,433     2,452,291     1,527,361     541,111  
                       

Adjusted EBITDA

    4,012,692     (1,237,829 )   2,680,565     947,247     (1,210,248 )
                       

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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.

Overview and 2009 Developments

        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 concentrated in two Rocky Mountain basins. 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 portfolio of proved reserves, as well as conventional and unconventional prospects, that we have the opportunity to explore, drill and develop.

        Our results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil and natural gas commodity prices, and the costs related to operating our properties.

        During 2009, Kodiak drilled eleven gross wells and 6.0 net wells and completed nine gross wells and 4.8 net wells as producers. Two wells were waiting on completion at year end and have been completed during the first quarter of 2010. Kodiak operated all of these wells. Four of the nine completed wells were drilled with horizontal lateral lengths greater than 8,000 feet and five were drilled with horizontal laterals less than 6,600 feet. Of the wells drilled and completed in 2009, the first well was put onto production in the second quarter of 2009.

        As of December 31, 2009, we had estimated proved reserves of 3.8 million barrels ("MBbls") of oil and 3.8 billion cubic feet ("BCF") of natural gas with a present value discounted at 10% of $39.1 million. Our reserves are comprised of 86% crude oil and 14% natural gas on an energy equivalent basis.

        We had crude oil sales of 500 barrels per day and gas sales of 604 Mcf per day in 2009. This was an increase of 187% for oil sales and 5% for gas sales over the volumes sold in 2008. During 2009, our revenues from oil and gas sales increased by $4.5 million or 67% to $11.3 million. This increase was due to a $7.0 million increase in sales volume as a result of successful production on new wells in 2009, partially offset by a negative effect of $2.5 million, due to lower average prices realized in 2009 than in 2008. Total oil and gas production expenses decreased 38% to $2.2 million in 2009 from $3.6 million in 2008. Of the $1.4 million decrease in 2009, $1.7 million is attributed to well workover operations charged to expense during 2008 that we did not incur in 2009.

        Our revenues are directly affected by oil and natural gas commodity prices, which can fluctuate dramatically. The commodity prices are beyond our control and are difficult to predict. During recent years, including 2009 and 2008, we have seen significant volatility in oil and natural gas prices. During 2009, we have seen oil prices steadily increase and natural gas prices remain depressed. During 2008, oil prices declined from record levels in early July 2008 of over $140 per Bbl to below $40 per Bbl in December 2008, while natural gas prices have declined from over $13 per Mcf to below $6 per Mcf over the same period. We believe that spot market prices reflect worldwide concerns about the global economy, producers' ability to ensure sufficient supply 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 constraint. Prices we have received have varied widely depending on commodity and location of salespoints. In 2009, we experienced improving crude oil prices in the Williston Basin while in Wyoming we elected to shut in gas production because of extremely low natural gas prices. Overall,

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the average crude oil price we received during 2009 was $58.35 per barrel versus $84.86 per barrel in 2008, while our average gas price received during 2009 was $2.84 per Mcf compared to $6.54 per Mcf in 2008.

        During 2009, the Company did not record any charges due to asset impairments. In 2008, our financial position and results of operations were affected significantly by an asset impairment related to the carrying value of our developed properties. In 2008, the value of Kodiak's proved reserves as calculated quarterly throughout the year did not exceed the costs included in the full cost pool. Consequently the Company recorded a cumulative asset impairment of $47.5 million during 2008.

2010 Outlook

        Our Board of Directors has approved a capital expenditure budget of $60 million for 2010, the majority of which is allocated to oil and gas activities to exploit the Bakken and Three Forks Formations in the Williston Basin of North Dakota and Montana. Of the total capital expenditure budget, the Company has allocated $43 million to the drilling and completion of 15 gross (9.5 net) Kodiak-operated wells in Dunn County, North Dakota, including the installation of associated surface facilities, $12 million for seven gross (2.0 net) non operated wells in Dunn County, North Dakota, and $5 million for three gross and (1.3 net) operated wells in Sheridan County, Montana and McKenzie County, North Dakota. Our working interest (WI) ranges from 35% to 100% in the operated 2010 drilling program, providing flexibility within the budget in identifying suitable well locations and in the timing and size of capital investment.

        The 2010 capital expenditure budget, both as to amount and allocation, is subject to 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. If we identify acreage that meets our strategic requirements, we may re-allocate our capital expenditure budget to permit us to complete a potential acreage acquisition. Alternatively, depending on the availability and terms of capital resources that may be available to us, we may increase our capital expenditure budget to allow us to acquire additional acreage. We expect to fund our capital budget primarily from cash on hand, anticipated cash flow from operations and borrowings under a potential reserve-based revolving line of credit that we anticipate will be available to us in the second quarter of 2010. If our existing and potential sources of liquidity are not sufficient to undertake our planned or revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties, sell interest in one or more of our properties or sell common shares. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our operating capital requirements. If we are 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, and we would be unable to implement our original exploration and drilling program.

        In February and early March 2010, we completed the MC #16-3-11H and the MC #16-3H wells located in our Moccasin Creek area on the Southwest portion of our leasehold. The MC #16-3-11H well had an initial production 24-hour test rate of 1,419 barrels of oil equivalent per day. The MC #16-3H well had an initial production 24-hour test rate of 1,425 barrels of oil equivalent per day. We operate both wells and have a 60% working interest and a 49% net revenue interest in these wells.

        We anticipate operating a two rig drilling program in the Williston Basin, principally on our acreage in Dunn County, North Dakota. We are in the process of taking delivery of Unit #118, for which we have a two year commitment on this rig. Kodiak took delivery of Unit Rig #117 in November 2008 and that contract expires in the fourth quarter of 2010 unless we mutually agree to extend the contract. In Dunn County, North Dakota, we currently have ten drilling pads approved by the Bureau of Indians Affairs, which can accommodate from one to four well bores each. We continue

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to develop our drilling program utilizing pad drilling which has proven to lower costs through fewer locations and by eliminating mobilization time between wells on each pad. During 2009, we drilled two wells off of four pads and one pad was drilled with a single well. We are currently drilling three wells from a pad and are looking to drill four wells off of future pads during 2010. Of the 22 gross wells budgeted in Dunn County, North Dakota for 2010, we expect to drill three wells with shorter laterals and expect the remaining wells to be drilled with longer horizontal laterals approaching 10,000 feet.

        The majority of our production in the Vermillion Basin is from non-operated wells. Currently, we have not allocated significant capital to this area as we anticipate being in a carried position for any exploratory capital expenditures in 2010. We expect one well drilled in 2008 to be reentered and horizontally drilled to evaluate the potential of the Baxter Shale interval.

Liquidity and Capital Resources

        The following table summarizes our sources and uses of cash for each of the three years ended December 31, 2009, 2008 and 2007.

 
  For the years ended December 31,  
 
  2009   2008   2007  

Capital Resources and Liquidity

                   

Cash and cash equivalents at end of the period

  $ 24,885,546   $ 7,581,265   $ 13,015,318  

Net cash provided by (used in) operating activities

    9,394,883     (2,174,519 )   2,073,412  

Net cash used in investing activities

    (28,155,174 )   (20,911,023 )   (47,909,507 )

Net cash provided by financing activities

    36,064,572     17,651,489     382,150  

Net cash flow

    17,304,281     (5,434,053 )   (45,453,945 )

        Our primary cash requirements are for exploration, development and acquisition of oil and gas properties. We have historically financed our operations, property acquisitions and capital investments from the proceeds of private and public offerings of our equity securities and, more recently to a limited extent, from cash generated from operations. During 2009, we did not generate sufficient cash flows from operations to sustain our 2009 capital expenditure budget. We issued equity during 2009, resulting in net cash provided by financing activities of approximately $36.1 million. As of December 31, 2009, we had working capital of $28.3 million as compared to $15.4 million at December 31, 2008, and no outstanding long-term debt. Our working capital as of December 31, 2009 included $24.9 million of cash and $7.3 million of prepaid tubular goods to be used in our 2010 drilling program.

        We expect to fund our 2010 capital budget primarily from cash on hand, anticipated cash flow from operations and borrowings under a potential reserve-based revolving line of credit that we anticipate will be available to us in the second quarter of 2010. If our existing and potential sources of liquidity are not sufficient to undertake our planned or revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties, sell interest in one or more of our properties or sell common shares. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our operating capital requirements. If we are 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, and we would be unable to implement our original exploration and drilling program.

        Our increase in cash from operations during 2009 is directly related to our successful drilling and completion operations accomplished during 2009. Our production and resulting revenue has increased as each well comes on to production. The decrease in cash from operations during 2008 was primarily from our workover activities on three wells which decreased our sales volumes and increased our operating expense. During 2008, we charged approximately $1.7 million of workover expense to lease

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operating expense, resulting in decreased cash flow. The oil and gas revenue decrease in 2008 from 2007 was primarily due to a decrease in oil sales volume.

        Our investing activities during the three years ended December 31, 2009 related primarily to the addition of oil and gas leases and oil and gas drilling activities. We recorded approximately $27.4 million in development, exploration and tubular purchase costs in 2009, $11.1 million in 2008 and $40.8 million in 2007. The remaining investing activity during 2009, 2008 and 2007 consisted primarily of equipment additions and changes in our restricted investments.

        Our financing activities in 2009 consisted of two equity offerings of our common stock. In May 2009, we issued 9,600,000 shares of common stock through a registered direct offering for gross proceeds of approximately $7.2 million. In October 2009, we issued 13,800,000 shares of common stock through a public offering for gross proceeds of approximately $30.4 million.

        Under our planned 2010 drilling and exploration program, the Company anticipates that our capital expenditures in the Williston Basin will be approximately $60 million. While we cannot fully assess our capital expenditures or the timing of expenditures in the Vermillion Basin as we do not operate the properties, we expect one well drilled in 2008 to be reentered and horizontally drilled to evaluate the potential of the Baxter Shale interval. However, the Company is carried on these costs under our amendment to our exploration and development agreement with Devon, effective August 1, 2009.

        As we operate the majority of our acreage, specifically the Williston acreage, we have the ability to adjust our drilling schedule to reflect the changing commodity price environment. Should we sell off some of our acreage and give up the right to operate, we will become subject to obligations imposed by others, without the ability to control our drilling schedule. Since we had not drawn against our credit facility (the "Credit Facility") with Bank of the West, NA ("BOTW") at December 31, 2009, our primary obligations at year end are our office lease and our two drilling rig contracts. During the second quarter of 2008, we entered into two-year contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled, and expires in 2010. Agreement terms require utilization of the rig and payment of day rates or the payment of standby rates if the rig is not utilized. The estimated termination fee for the first rig is approximately $3.5 million as of December 31, 2009. The termination fee on the first rig will continue to decrease as long as the rig remains active. We anticipate placing the second rig into operation in late March 2010. This rig entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled. Agreement terms require utilization of the rig and payment of day rates or the payment of standby rates if the rig is not utilized. The estimated termination fee for the second rig is approximately $5.1 million as of December 31, 2009. The termination fee on the second rig will continue to decrease as long as the rig remains active.

        On September 11, 2008, our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc. (our "Subsidiary"), executed a $20 million Credit Facility with BOTW. Borrowings made under the Credit Facility were guaranteed by us and secured by mortgages on substantially all of our producing oil and gas properties. The Credit Facility also provided for letters of credit that could be used for general corporate purposes and included a commitment by our Subsidiary to enter into an ISDA Master Agreement with BOTW that would govern hedging transactions (the "ISDA Agreement").

        On March 9, 2010, our Subsidiary elected to terminate the Credit Facility and the ISDA Agreement in order to permit us to establish our new credit facility with a lender on terms that would include our Bakken properties within the borrowing base. The termination of the Credit Facility and of the ISDA Agreement will be effective as of March 12, 2010. In connection with the termination, our guarantee to BOTW all of the obligations of our Subsidiary under the Credit Facility and the other

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loan documents also terminated. There were no revolving loans outstanding, and we will not incur any penalties for early termination.

        We have entered into discussions with several financial institutions with the intention of establishing a reserve-based revolving line of credit. We are currently evaluating several term sheets and believe that we will enter into a line of credit with a financial institution in the second quarter of 2010. We cannot assure you, however, that a credit facility will be available to us on terms acceptable to us, or at all.

        If we borrow funds under a new credit agreement, we will be obligated to make periodic interest or other debt service payments and may be subject to additional restrictive covenants. The ability to borrow 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. Should we seek to raise additional capital through the issuance and sale of equity securities, the sales, if successfully completed, may be at prices below the market price of our stock, and our shareholders may suffer significant dilution.

Operating Results

Fiscal Year Ended December 31, 2009 Compared to Fiscal Year Ended December 31, 2008

        Oil sales revenues.    Oil sales revenues increased by $5,254,917 to $10,651,698 for the year ended December 31, 2009 as compared to oil sales of $5,396,781 for the year ended December 31, 2008. Our oil sales volume increased 187% in 2009 as compared to 2008. Oil sales volumes were 182,558 Bbl for the year ended December 31, 2009, as compared to 63,595 Bbl for the same period in 2008. The increased revenue in 2009 was attributable to the positive impact of increased volumes of oil sales, offset in part by lower commodity prices. The average price we realized on the sale of our oil decreased from $84.86 per barrel for the year ended December 31, 2008, to $58.35 for the year ended December 31, 2009.

        Natural Gas sales revenues.    Natural gas sales revenues decreased by $746,462 to $625,360 for the year ended December 31, 2009, from $1,371,822 for the same period of 2008. The average price we realized on the sale of our natural gas was $2.84 per Mcf in 2009 compared to $6.54 per Mcf in 2008. This 57% decline in natural gas prices realized resulted in a $776,695 decline in natural gas revenue in 2009 as compared to 2008. Natural gas sales volumes were 220,455 Mcf for the year ended December 31, 2009, compared to 209,815 Mcf for the same period in 2008. This 5% increase in natural gas volumes partially offset the decline in natural gas revenue by $30,232.

        Interest and Other Income.    Interest and other income decreased by $135,536 to $60,651 in 2009 from $196,187 for the same period in 2008 due to both a decrease in average investible cash throughout the year and lower interest rate paid for funds held with our banks.

        Oil and gas production expense.    Our oil and gas production expense decreased by $1,358,198 to $2,220,382 for the year ended December 31, 2009, from $3,578,580 for the same period in 2008. The decrease is primarily due to workover expense of $1,709,667 recorded in 2008 which was partially offset by additional production expense attributable to each new well coming on to production during 2009.

        Depletion, depreciation, amortization and abandonment liability accretion ("DDA") expense.    Our depletion, depreciation, amortization and abandonment liability accretion expense decreased by $1,013,644 to $3,158,433 for the fiscal year ended December 31, 2009, from $4,172,077 for the same period in 2008. Although increased production volumes impact DDA by increasing cost on a units of production basis, due to impairment charges taken in 2008, the full cost pool was lower resulting in a lower DDA rate charged for 2009.

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        Asset impairment.    There were no asset impairment charges during 2009. During the last half of 2008, crude oil and natural gas prices dropped from their highs set in the summer of 2008 and the Company's full cost pool exceeded the ceiling by approximately $47.5 million after taking into account decrease in prices following the period ends. Subsequent to the end of the third and fourth quarters of 2008, there was no recovery in price and therefore impairment expenses of $15.5 million and $32.0 million were recorded in the third and fourth quarters of 2008, respectively.

        General and administrative expense.    General and administrative expense increased by $309,995 to $8,522,192 for the fiscal year ended December 31, 2009, from $8,212,197 for the same period in 2008. Excluding the non-cash stock-based compensation expense in each period our general and administrative expenses increased by $432,544 or 9% during 2009 as compared to the same period in 2008. We recorded lower stock-based compensation expense of $3,428,884 for the year ended December 31, 2009 compared to $3,551,433 recorded for the same period in 2008, related to options and restricted stock issued to officers, directors and employees. The reduction in the stock-based compensation expense is due in part to the reversal recorded of non-vested performance based-stock options that expired as of March 20, 2009. Stock-based compensation expense related to the expired performance based stock options was approximately $122,000. Additionally, on December 31, 2009 certain officers and directors voluntarily cancelled stock options issued in 2007. The unamortized expense related to these cancelled options of approximately $413,000 was recognized in stock-based compensation expense as of December 31, 2009.

        Net loss.    Our net loss improved or decreased by $53,934,766 to a net loss of $2,563,298 for the year ended December 31, 2009, from a net loss of $56,498,064 for 2008. As more fully described above, the asset impairment of $47,500,000 in 2008 was the primary cause of the decrease in net loss from 2008. In addition, our increased oil production and resulting oil revenue contributed to the improvement or decrease in net loss.

        Adjusted EBITDA.    Our Adjusted EBITDA increased by $5,250,521 to $4,012,692 for the year ended December 31, 2009, from $(1,237,829) for the same period of 2008. As shown in the following table, this increase is the primarily the result of increased revenues from increased oil and gas production. For further discussion of this non-GAAP measure and a reconciliation of this measure to net income, see Non-GAAP Financial Measure in Item 4 of this 10-K.

 
  For the Year Ended December 31,  
 
  2009   2008   Change  

Oil and gas production revenues

  $ 11,277,058   $ 6,768,603   $ 4,508,455  

Interest revenue

    60,651     196,187     (135,536 )
               

Total revenue

    11,337,709     6,964,790     4,372,919  

Oil and gas production expense

    2,220,382     3,578,580     (1,358,198 )

General and administrative expense excluding stock compensation and gain (loss on currency)

    5,104,635     4,624,039     480,596  
               

Adjusted EBITDA

  $ 4,012,692   $ (1,237,829 ) $ 5,250,521  
               

Fiscal Year Ended December 31, 2008 Compared to Fiscal Year Ended December 31, 2007

        Oil sales revenues.    Oil sales revenues decreased by $1,367,236 to $5,396,781 for the year ended December 31, 2008, from $6,764,017 for 2007. This decrease is attributed to a $3,337,586 negative impact due to a 38% decrease in volume offset and by a $1,970,350 positive impact due to a 29% increase in average price. During the second and third quarter of 2008, three operated oil wells were shut in pending workover and completion activities. This contributed to the decline in our oil sales

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volumes to 63,595 barrels for 2008 compared to 102,914 barrels for the same period in 2007, whereas the average price we realized on the sale of our oil increased to $84.86 per barrel for the year ended December 31, 2008, from $65.72 for the same period in 2007.

        Natural Gas sales revenues.    Natural gas sales revenues increased by $318,491 to $1,371,822 for the year ended December 31, 2008, from $1,053,332 for the same period of 2007 $62,804 of the increase was due to a 5% increase in volume and $255,687 of the increase was due to a 24% increase in average price. Natural gas sales volumes were 209,815 Mcf for the year ended December 31, 2008, compared to 200,191 Mcf for the same period in 2007 and the average price we realized on the sale of our natural gas was $6.54 per Mcf in 2008 compared to $5.26 per Mcf in 2007. During the fourth quarter of 2008, natural gas prices in Wyoming declined to a level that we decided to shut-in our Wyoming operated wells until prices improve.

        Interest Income.    Interest income decreased by $1,306,842 to $196,187 in 2008 from $1,503,029 for the same period in 2007 due to a decrease in average investible cash throughout the year.

        Oil and gas production expense.    Our oil and gas production expense increased by $1,820,863 to $3,578,580 for the year ended December 31, 2008, from $1,757,717 for the same period in 2007. The increase is primarily due to workover expense of $1,709,667 recorded during the year.

        Depletion, depreciation, amortization and abandonment liability accretion ("DDA") expense.    Our depletion, depreciation, amortization and abandonment liability accretion expense decreased by $1,034,554 to $4,172,077 for the fiscal year ended December 31, 2008, from $5,206,631 for the same period in 2007. Due to impairment charges taken in 2007 and 2008, the full cost pool was lower resulting in a lower DDA charge for 2008.

        Asset impairment.    During the last half of 2008, crude oil and natural gas prices dropped from their highs set in the summer of 2008 and the Company's full cost pool exceeded the ceiling by approximately $47.5 million after taking into account decrease in prices following the period ends. Subsequent to the end of the third and fourth quarters of 2008, there was no recovery in price and therefore impairment expenses of $15.5 million and $32.0 million were recorded in the third and fourth quarters of 2008, respectively.

        In 2007, we recorded an impairment of $34.0 million primarily as the result of our inability to establish production and qualified reserves in its deep Vermillion Basin project, uneconomic natural gas prices in Wyoming, and the impairment of certain undeveloped properties in Wyoming and North Dakota.

        General and administrative expense.    General and administrative expense increased by $1,670,278 to $8,212,197 for the fiscal year ended December 31, 2008, from $6,541,919 for the same period in 2007. Included in the general and administrative expense for the fiscal year ended December 31, 2008 is a stock-based compensation charge of $3,551,433 for options issued to officers, directors and employees compared to $2,452,291 for the year ended December 31, 2007. The increase in general and administrative expenses for the fiscal year ended December 31, 2008, also reflects an increase in our level of activity and an increase in the number of employees. As of December 31, 2008, we had 17 full-time employees and two contract consultants as compared to 15 full-time employees and three contract consultants at December 31, 2007. Salary and related expenses decreased by $578,897 to $2,336,276 for the year ended December 31, 2008, from $2,915,173 in 2007. This decrease is due to the reduction in employee bonuses in 2008 versus 2007, partially offset by the addition of two new employees in 2008. Also included in general and administrative expense is our gain on currency exchange. In 2008, a decrease in the value of the Canadian dollar resulted in a loss of $36,725 on currency exchange as compared to a gain in 2007 of $792,467.

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        Net loss.    Our net loss increased by $18,312,174 to a net loss of $56,498,064 for the year ended December 31, 2008, from a net loss of $38,185,890 for 2007. As more fully described above, the asset impairment of $47,500,000 in 2008 was the primary cause of the increase as compared to an asset impairment charge of $34,000,000 in 2007. In addition, the decrease in oil production revenue, interest income and the increase in oil and gas production expense contributed to the increase in net loss.

        Adjusted EBITDA.    Our Adjusted EBITDA decreased by $3,918,395 to $(1,237,829) for the year ended December 31, 2008, from $2,680,565 for the same period of 2007. As shown in the following table, this decrease is the primarily the result of decreased revenues and increased production and general and administrative expenses. For further discussion of this non-GAAP measure and a reconciliation of this measure to net income, see Non-GAAP Financial Measure in Item 4 of this 10-K.

 
  For the Year Ended December 31,  
 
  2008   2007   Change  

Oil and gas production revenues

  $ 6,768,603   $ 7,817,349   $ (1,048,746 )

Interest revenue

    196,187     1,503,029     (1,306,842 )
               

Total revenue

    6,964,790     9,320,378     (2,355,588 )

Oil and gas production expense

    3,578,580     1,757,717     1,820,863  

General and administrative expense excluding stock compensation

    4,624,039     4,882,095     (258,056 )
               

Adjusted EBITDA

  $ (1,237,829 ) $ 2,680,566   $ (3,918,395 )
               

Financial Instruments and Other Instruments

        As at December 31, 2009, we had cash, accounts payable and accrued liabilities which are carried at approximate fair value because of the short maturity date of those instruments. 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 stage natural resource company, we do not normally engage in research and there were no development activities, or research and development expenditures made in the last three fiscal years.

Trend Information

        During 2009, commodity prices stabilized from the historic volatility experienced during 2008. With oil currently near $80 per barrel, drilling activity in certain areas, including near our operating areas, has increased over the low activity we experienced in early 2009. Currently, qualified employees are available; however we still must compete for employees within our industry. Some or all of these situations are likely to have a material effect upon our net sales or revenues, income from continuing operations, profitability, liquidity or capital resources, or cause reported financial information not necessarily to be indicative of future operating results or financial condition.

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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Subsequent Event

Commodity Derivative Agreement

        In February 2010, the Company entered into its first commodity derivative contract. We utilized a "no premium" collar to hedge the effect of price changes on a portion of its future oil production. The objective of our hedging activity and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. As we develop our hedging strategy, 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 the Company's existing positions and use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional commodity price risk.

        The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contract is currently with a single counterparty. The Company has netting arrangements with the counterparty that provides for the offset of payables against receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

        Our commodity derivative contract entered into during February 2010 is summarized below:

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

Collar

  BP North America   NYMEX     200   $ 70.00/$90.00     Mar 1 - Dec 31, 2010  

Contractual obligations

        The following table lists as of December 31, 2009, 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
 

Contractual Obligations

                               

Long-Term Obligations—Office Facilities

  $ 747,340   $ 289,997   $ 303,171   $ 154,172      

Drilling Rig Obligations

    8,604,850     3,524,850     5,080,000          

        During the second quarter of 2008, the Company entered into two-year contracts for the use of two new-build drilling rigs, which are described in this section under the heading "Liquidity and Capital Resources".

        We have not included asset retirement obligations as discussed in note 2 of the accompanying audited financial statements, as we cannot determine with accuracy the timing of such payments.

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.

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Oil and Natural Gas Reserves

        We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. 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 less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the new SEC rules, we prepared our oil and gas reserve estimates as of December 31, 2009 using the average, first-day-of—the- month price during the 12-month period ending December 31, 2009. In prior years through September 30, 2009, we used the year-end or quarter ended price. Prior to December 31, 2009, subsequent commodity price increases could be utilized to calculate the ceiling value.

        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, natural gas, and natural gas liquids 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 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 at each quarter 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.

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Impairment of Long-lived Assets

        We record our property and equipment at cost. The cost of our unproved properties is withheld from the depletion base as described above, until such a time as the properties are either developed or abandoned. We review these properties quarterly for possible impairment. We provide an impairment allowance on unproved property when we determine that the property will not be developed or the carrying value will not be realized. We evaluate the reliability of our proved properties and other long-lived assets whenever events or changes in circumstances indicate that the recording of impairment may be appropriate. Our impairment test compares the expected undiscounted future net revenue from a property, using escalated pricing, with the related net capitalized costs of the property at the end of the applicable period. When the net capitalized costs exceed the undiscounted future net revenue of a property, the cost of the property is added to the full cost pool.

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 produced natural gas and crude oil. 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 use our knowledge of our properties, their historical performance, the anticipated effect of weather conditions during the month of production, NYMEX and local spot market prices and other factors as the basis for these estimates. We record the variances between our estimates and the actual amounts we receive in the month payment is received.

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 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. Our estimated asset retirement obligations are reflected in our depreciation, depletion and amortization calculations over the remaining life of our oil and gas properties.

Stock-Based Compensation

        We account for stock-based compensation under the provisions of ASC Topic 718. This guidance requires us to record expense associated with the fair value of stock-based compensation. We currently use the Black-Scholes option valuation model to calculate stock based compensation.

Oil and Natural Gas Properties—Full Cost Method of Accounting

        We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. We record all capitalized cost into a single cost center as all operations are conducted within The United States. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

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        Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.

        Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether impairment has occurred. 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 the full cost pool and becomes subject to depletion calculations.

        Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%. Royalties paid, net of any tax credits, received are netted against oil and natural gas sales.

        In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs less accumulated depletion from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers. The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes. Under the full cost method of accounting, capitalized oil and natural 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 natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize an impairment.

Foreign Currency Fluctuations

        Monetary items denominated in a foreign currency, other than U.S. dollars, are converted into U.S. dollars at exchange rates prevailing at the balance sheet date. Foreign currency denomination revenue and expense items are translated at exchange rates prevailing at the transaction date. Gains or losses arising from the translations are included in operations.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

        Our primary market risk consists of market changes in oil and natural gas prices. Prospective revenues from the sale of products or properties will be impacted by oil and natural gas prices. A $1.00 per Mcf change in the market price of natural gas would result in a change of approximately $221,000 in our gross gas production revenue for the fiscal year ended December 31, 2009. A $1.00 per barrel change in the market price of oil would result in a change of approximately $183,000 in our gross oil production revenue for the fiscal year ended December 31, 2009. The impact on any potential sale of property cannot be readily determined.

Interest Rate Risk

        We currently maintain some of our available cash in redeemable short-term investments, classified as cash equivalents, and our reported interest income from these short-term investments could be adversely affected by any material changes in U.S. dollar interest rates. A 1% change in the interest rate would result in a change of approximately $249,000 in our interest income for the fiscal year ended December 31, 2009 if all of our cash were invested in interest-bearing notes.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

        We have audited the accompanying consolidated balance sheets of Kodiak Oil & Gas Corp. and subsidiaries as of December 31, 2009 and 2008, and the accompanying consolidated statements of operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.

        We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Kodiak Oil & Gas Corp.'s and subsidiaries' internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 11, 2010 expressed an unqualified opinion on the effectiveness of Kodiak Oil & Gas Corp.'s internal control over financial reporting.

/s/ HEIN & ASSOCIATES LLP

Denver, Colorado
March 11, 2010

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KODIAK OIL & GAS CORP.

CONSOLIDATED BALANCE SHEETS

 
  December 31,
2009
  December 31,
2008
 

ASSETS

             

Current Assets:

             
 

Cash and cash equivalents

  $ 24,885,546   $ 7,581,265  
 

Accounts receivable

             
   

Trade

    2,562,779     1,934,818  
   

Accrued sales revenues

    1,909,221     516,870  
 

Inventory, prepaid expenses and other

    7,647,870     10,621,980  
           
     

Total Current Assets

    37,005,416     20,654,933  
           

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

             
 

Proved oil and gas properties

    123,259,252     97,934,058  
 

Unproved oil and gas properties

    12,068,156     11,985,533  
 

Wells in progress

    2,691,107     728,093  
 

Less-accumulated depletion, depreciation, amortization, accretion and asset impairment

    (95,782,438 )   (92,804,911 )
           
 

Net oil and gas properties

    42,236,077     17,842,773  
           

Other property and equipment, net of accumulated depreciation of $284,535 in 2009 and $270,620 in 2008

    441,531     272,705  

Restricted investments

        246,068  
           

Total Assets

  $ 79,683,024   $ 39,016,479  
           
       

LIABILITIES AND STOCKHOLDERS' EQUITY

             

Current Liabilities:

             
 

Accounts payable and accrued liabilities

  $ 7,742,617   $ 4,125,335  
 

Advances from joint interest owners

    951,815     1,105,740  
           
     

Total Current Liabilities

    8,694,432     5,231,075  

Noncurrent Liabilities:

             
 

Asset retirement obligation

    1,060,210     787,180  
           
     

Total Liabilities

    9,754,642     6,018,255  
           

Commitments and Contingencies—Note 7

             

Stockholders' Equity:

             
 

Common stock—no par value; unlimited authorized

             
 

Issued and outstanding: 118,879,931 shares in 2009 and 95,129,431 shares in 2008

             
 

Contributed surplus

    175,791,301     136,297,845  
 

Accumulated deficit

    (105,862,919 )   (103,299,621 )
           
     

Total Stockholders' Equity

    69,928,382     32,998,224  
           

Total Liabilities and Stockholders' Equity

  $ 79,683,024   $ 39,016,479  
           

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

 
  For the Years Ended December 31,  
 
  2009   2008   2007  

Revenues:

                   
 

Gas production

  $ 625,360   $ 1,371,822   $ 1,053,331  
 

Oil production

    10,651,698     5,396,781     6,764,017  
 

Interest & other

    60,651     196,187     1,503,029  
               
   

Total revenue

    11,337,709     6,964,790     9,320,377  
               

Cost and expenses:

                   
 

Oil and gas production

    2,220,382     3,578,580     1,757,717  
 

Depletion, depreciation, amortization and accretion

    3,158,433     4,172,077     5,206,631  
 

Asset impairment

        47,500,000     34,000,000  
 

General and administrative

    8,522,192     8,212,197     6,541,919  
               
   

Total costs and expenses

    13,901,007     63,462,854     47,506,267  
               

Net loss

  $ (2,563,298 ) $ (56,498,064 ) $ (38,185,890 )
               

Basic & diluted weighted-average common shares outstanding

    103,688,733     90,739,316     87,742,996  
               

Basic & diluted net loss per common share

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

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

STATEMENTS OF STOCKHOLDERS' EQUITY

 
  Common Stock
Shares
  Contributed
Surplus
  Accumulated
Deficit
  Total
Equity
 

Balance December 31, 2006:

    87,548,426   $ 112,260,482   $ (8,615,667 ) $ 103,644,815  

Issuance of stocks for cash:

                         
 

—pursuant to exercise of options

    363,500     382,150           382,150  

Employee stock grants

    81,000     125,200           125,200  

Stock-based compensation

          2,327,091           2,327,091  

Net loss

                (38,185,890 )   (38,185,890 )
                   

Balance December 31, 2007:

    87,992,926   $ 115,094,923   $ (46,801,557 ) $ 68,293,366  
                   

Issuance of stocks for cash:

                         
 

—pursuant to equity offering

    6,820,005     18,755,000           18,755,000  
 

—pursuant to exercise of options

    312,500     180,000           180,000  

Share issuance costs

          (1,283,511 )         (1,283,511 )

Employee stock grants

    4,000     154,655           154,655  

Stock-based compensation

          3,396,778           3,396,778  

Net loss

                (56,498,064 )   (56,498,064 )
                   

Balance December 31, 2008:

    95,129,431   $ 136,297,845   $ (103,299,621 ) $ 32,998,224  
                   

Issuance of stocks for cash:

                         
 

—pursuant to equity offering

    23,400,000     37,560,000           37,560,000  
 

—pursuant to exercise of options

    350,500     333,450           333,450  

Share issuance costs

          (1,828,878 )         (1,828,878 )

Stock-based compensation

          3,428,884           3,428,884  

Net loss

                (2,563,298 )   (2,563,298 )
                   

Balance December 31, 2009:

    118,879,931   $ 175,791,301   $ (105,862,919 ) $ 69,928,382  
                   

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS

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KODIAK OIL & GAS CORP.

CONSOLIDATED STATEMENTS OF CASHFLOWS

 
  For the Years Ended December 31,  
 
  2009   2008   2007  

Cash flows from operating activities:

                   
 

Net loss

  $ (2,563,298 ) $ (56,498,064 ) $ (38,185,890 )

Reconciliation of net loss to net cash provided by (used in) operating activities:

                   
   

Depletion, depreciation, amortization and accretion

    3,158,433     4,172,077     5,206,631  
   

Asset impairment

        47,500,000     34,000,000  
   

Asset retirement

            (29,893 )
   

Stock based compensation

    3,428,884     3,551,433     2,452,291  
 

Changes in current assets and liabilities:

                   
   

Accounts receivable—trade

    (627,961 )   (560,975 )   503,342  
   

Accounts receivable—accrued sales revenue

    (1,392,351 )   272,782     (122,661 )
   

Prepaid expenses and other

    3,071,690     (767,069 )   (95,289 )
   

Accounts payable and accrued liabilities

    4,319,486     155,297     (1,655,119 )
               

Net cash provided by (used in) operating activities

    9,394,883     (2,174,519 )   2,073,412  
               

Cash flows from investing activities:

                   
   

Oil and gas properties

    (24,289,407 )   (11,209,258 )   (47,649,681 )
   

Prepaid drilling & equipment

    (278,280 )   (54,850 )   (229,210 )
   

Prepaid tubular goods

    (3,833,555 )   (9,655,915 )    
   

Restricted investment: designated as restricted

            (30,616 )
   

Restricted investment: undesignated as restricted

    246,068     9,000      
               

Net cash (used in) investing activities

    (28,155,174 )   (20,911,023 )   (47,909,507 )
               

Cash flows from financing activity:

                   
   

Proceeds from the issuance of shares

    37,893,450     18,935,000     382,150  
   

Issuance costs

    (1,828,878 )   (1,283,511 )    
               

Net cash provided by financing activities

    36,064,572     17,651,489     382,150  
               

Net change in cash and cash equivalents

    17,304,281     (5,434,053 )   (45,453,945 )

Cash and cash equivalents at beginning of the period

   
7,581,265
   
13,015,318
   
58,469,263
 
               

Cash and cash equivalents at end of the period

  $ 24,885,546   $ 7,581,265   $ 13,015,318  
               

Supplemental cash flow information

                   
 

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

  $ 601,060   $ 1,457,189   $ 1,544,868  
               
 

Asset retirement obligation

  $ 177,593   $ (65,143 ) $ 526,868  
               

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE 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 NYSE Amex and whose 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 natural gas and crude oil entirely in the western United States.

        The Company 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. All significant inter-company balances and transactions have been eliminated in consolidation. The majority of the Corporation's business is transacted in US dollars and, accordingly, the financial statements are expressed in US dollars.

Use of Estimates in the Preparation of Financial Statements

        The preparation of the financial statements in conformity with generally accepted accounting principles 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. The Company evaluates its estimates on an on-going basis and bases its estimates on historical experience and on various other assumptions it believes to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oil and gas reserves.

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.

        As of December 31, 2009, the Company had approximately $23.4 million in money market accounts with its banks. The money market accounts are 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, 2009.

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, 2009 and December 31, 2008 respectively, there was approximately $0 and $9.7 million of deposits made and recorded. The cost basis of the tubular goods is depreciated as a component of oil and gas properties once the inventory is used

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)


in drilling operations. The deposit is non-refundable. At December 31, 2009 and December 31, 2008 respectively, the market value of the Company's tubular goods inventory approximated the cost basis.

Concentration of Credit Risk

        The Company's cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company may at times have 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. The Company assesses the recoverability of all material trade and other receivables to determine their collectability on a quarterly basis. We accrue a reserve, on a receivable when, based on management's judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. In determining the amount of the reserve, management must analyze the aging of account receivable at the date of the consolidated financial statements and assess collectability based on historic results, current collection trends and an evaluation of economic conditions. If estimates are inaccurate, we may incur gains or losses that could have a material effect on our results of operations. However, to date the Company has had minimal bad debts.

Significant Customers

        During the year ended December 31, 2009, over 55% of the Company's production was sold to one customer, Plains Marketing LP. However, the Company does not believe that the loss of a single purchaser, including Plains Marketing LP, 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, 2009, 2008 and 2007 purchases by the following companies exceeded 10% of the total oil and gas revenues of the company.

 
  For the Years Ended
December 31,
 
 
  2009   2008   2007  

Plains Marketing LP

    55 %   0 %   0 %

Eighty Eight Oil LLC

    16 %   84 %   80 %

ABQ Gas Marketing

    2 %   4 %   12 %

Oil and Gas Producing Activities

        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"). The Company records all capitalized costs into a single cost center as all operations are conducted with The United States. 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)


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 exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves as determined by the Company's engineers and audited by independent petroleum engineers. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, 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. During 2009 and 2008 approximately $0 and $17.2 million respectively, of unproved land costs were reclassified to proved property and was included in the ceiling test and depletion calculations. In 2007, approximately $1.1 million was reclassified to proved property and was included in the ceiling test and depletion calculations.

        Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company's overall value. 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. 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 Securities and Exchange Commission (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.

        The optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Most of the Company's wells have been producing for a period of less than six years and for some, less than a year. Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company's estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company's wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on a quarterly basis in accordance with applicable rules established by the SEC and may be adjusted based on that data.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

        Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether impairment has occurred. 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 the full cost pool and becomes subject to depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our 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. 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. The present value of estimated future net revenues is computed by applying current prices of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves assuming the continuation of existing economic conditions.

        During the last half of 2008, oil and natural gas prices decreased significantly from the record highs seen during the summer of 2008. Natural gas prices in the Rocky Mountains decreased significantly due to the reduction in take-away capacity caused by pipeline maintenance and repairs during the fall of 2008. The Company removed four wells with approximately 348,000 BOE from its proved undeveloped (PUD) category of its reserve base. The removal of these proved undeveloped wells from the reserve base was due to one well that became uneconomic based on 2008 pricing and anticipated capital requirements related to the well and three wells that the Company removed from its drilling plans. After taking into account the decreases in the reserve base due to the above factors and the decreases in prices an impairment expense of $47.5 million was recorded for the year ended 2008.

        In 2007, primarily as the result of the Company's inability to establish production and qualified reserves in its deep Vermillion Basin project, low natural gas prices in Wyoming, and the impairment of certain undeveloped properties in Wyoming and North Dakota, the Company recorded an impairment expense of $34.0 million.

Wells in Progress

        Wells in progress at December 31, 2009 and December 31, 2008, 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 is then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods. At December 31, 2009, the Company had two wells waiting completion in its Bakken oil play on the Fort Berthold Indian Reservation ("FBIR') and four wells waiting completion on its Vermillion Basin prospect.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

Impairment of Long-lived Assets

        The Company's unproved properties are evaluated quarterly for the possibility of potential impairment. For the year ended December 31, 2009, no impairment was recorded. For the year ended December 31, 2008, the Company reclassified approximately $17.2 million of unproved property cost to the full cost pool. The Company recorded an impairment expense of $47.5 million in 2008.

        For the year ended December 31, 2007 the Company reclassified approximately $1.1 million of unproved property costs to the full cost pool. The Company recorded an impairment expense of $34.0 million in 2007.

Deferred Financing Costs

        Deferred financing costs include debt issuance costs incurred in connection with the Company's Credit Agreement, which are being amortized over the two year term of the Credit Facility (see Note 8). The Company recorded amortization expense of $25,488 and $7,330 as of December 31, 2009 and 2008, respectively.

Other 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.

Fair Value of Financial Instruments

        The Company's financial instruments, including cash and cash equivalents, are carried at cost, which approximates fair value due to the short-term maturity of these instruments.

Revenue Recognition

        The Company records revenues from the sales of natural gas and crude oil when they are produced and sold. The Company may have an interest with other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company also reduces revenue for other owners' gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's over and under produced gas balancing positions are considered in the Company's proved oil and gas revenues. Gas imbalances at December 31, 2009, and December 31, 2008 were not significant.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

Asset Retirement Obligation

        The Company follows accounting for asset retirement obligations in accordance with ASC 410.20, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are included in the ceiling test calculation. Asset retirement obligations incurred in 2009 are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of December 31, 2009, and December 31, 2008, the Company has recorded a net asset of $603,526 and $501,900 and a related liability of $1,060,210 and $787,180, respectively, for asset retirement obligations.

        The information below reconciles the value of the asset retirement obligation for the periods presented.

 
  For the Period Ended  
 
  December 31, 2009   December 31, 2008  

Balance beginning of period

  $ 787,180   $ 874,498  
 

Liabilities incurred

    251,671      
 

Liabilities settled

    (74,078 )   (147,252 )
 

Accretion expense

    95,437     59,934  
           

Balance end of period

  $ 1,060,210   $ 787,180  
           

Off Balance Sheet Arrangements

        On September 14, 2009, the Company entered into an amendment to one of its two drilling rig contracts (the "First Amendment"). Under the terms of the original drilling rig contract (the "Original Contract"), which has a two-year drilling commitment, the Company was scheduled to take delivery of the subject rig in February 2009. On December 9, 2009, the Company entered into a second amendment ("Second Amendment") to this drilling rig contract whereby the Company has agreed to take delivery of the subject rig during the first quarter of 2010. Under the terms of the Second Amendment, delay payments required under the First Amendment ceased as of December 15, 2009. The maximum termination fee payable by the Company would be $5.1 million, against which a portion of the Delay Payments would be applied in the form of a credit.

        Other than standard operating leases, the Company did not have any off-balance sheet financing arrangements at December 31, 2009 and December 31, 2008.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 2—Basis of Presentation and Significant Accounting Policies (Continued)

Recently Adopted Accounting Pronouncements

        In June 2009, the Financial Accounting Standards Board ("FASB") issued The FASB Accounting Standards Codification ("ASC') which became effective for interim and annual reporting periods ending after September 15, 2009. The Codification is the source of authoritative U.S. GAAP recognized by the FASB. The adoption of the Codification did not have a material impact on the Company's financial position or results of operations.

        On December 31, 2008, the SEC adopted a final rule that amends its oil and gas reporting requirements. The revised rules changed the way oil and gas companies report their reserves in the financial statements. Definitions were updated to be consistent with Petroleum Resource Management System (PRMS). The rules also revise the prices used for reserves in determining depletion and the full cost ceiling test from a period end price to a twelve month average of the first day of the month prices. Other key revisions include, the inclusion of non-traditional resources in reserves, the allowance for use of new technologies in determining reserves, optional disclosure of probable and possible reserves and other new disclosures. The revised rules became effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending December 31, 2009, and after. The adoption of the final SEC ruling on disclosure requirements and the implementation of the new reporting requirements relating to our oil and gas reserves did not have a material impact on the consolidated results of operations, financial position or liquidity.

        In May 2009, the ASC guidance for subsequent events was updated to establish general standards of accounting for and disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The Company adopted this guidance effective April 1, 1009. See Note 12 for the Company's disclosures about subsequent events.

        In June 2008, the ASC guidance was updated to provide clarification as to whether instruments granted in share-based payment transactions are participating securities prior to vesting, and therefore, need to be included in computing earnings per share under the two-class method provided under ASC 260—Earnings Per Share. The Company adopted this standard effective January 1, 2009. The adoptions of this guidance did not have a material impact on the Company's financial position, results of operations or cash flows.

Recently Issued Accounting Pronouncements

        In January 2010, the Financial Accounting Standards Board ("FASB") issued an Accounting Standards Update ("ASU") to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules discussed above. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 3—Oil and Gas Property

        The following table presents information regarding the Company's net costs incurred in the purchase of proved and unproved properties, and in the exploration and development activities:

 
  For the Years Ended December 31,  
 
  2009   2008   2007  

Property Acquisition costs:

                   
 

Proved

  $   $   $  
 

Unproved

    462,542         4,285,277  

Exploration costs

    5,412     8,893,293     28,960,843  

Development costs

    26,902,877     2,163,143     11,869,900  
               
   

Total

  $ 27,370,831   $ 11,056,436   $ 45,116,020  
               
   

Total excluding asset retirement obligation

  $ 27,193,238   $ 10,909,184   $ 44,576,209  
               

        Depletion expense related to the proved properties per equivalent BOE of production for the years ended December 31, 2009, 2008, and 2007 were $13.23, $32.18, and $39.30, respectively.

        At December 31, 2009 and 2008, the Company's unproved properties consisted of leasehold acquisition costs in the following areas:

 
  2009   2008  

Colorado

  $ 125,959   $ 124,656  

Montana

    910,665     803,386  

North Dakota

    9,994,408     10,038,305  

Wyoming

    1,037,124     1,019,186  
           

  $ 12,068,156   $ 11,985,533  
           

        The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2009 by the year in which such costs were incurred:

 
  Unproved
Additions by Year
 

Prior

  $ 2,928,654  

2007

    1,758,439  

2008

    7,298,440  

2009

    82,623  
       

Total

  $ 12,068,156  
       

        During 2008 approximately $17.2 million of unproved land costs was reclassified to proved property and was included in the ceiling test and depletion calculations.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4—Wells in Progress

        The following table reflects the net changes in capitalized additions to wells in progress during 2009 and 2008.

 
  For the Year Ended
December 31, 2009
  For the Year Ended
December 31, 2008
 

Beginning balance

  $ 728,093   $ 414,074  

Additions to capital wells in progress costs pending the determination of proved reserves

    16,127,748     728,093  

Reclassifications to wells, facilities, and equipment based on the determination of proved reserves to full cost pool

    (14,164,734 )   (414,074 )
           

Ending balance

  $ 2,691,107   $ 728,093  
           

        The following table provides an aging of capitalized wells in progress costs based on the date the drilling was completed and the number of projects for which wells in progress have been capitalized since the completion of drilling.

 
  For the Years Ended
December 31
 
 
  2009   2008  

Wells in progress capitalized for one year or less

  $ 2,465,078   $ 728,093  

Wells in progress capitalized for one year or more

    226,029      
           

Ending balance at December 31

  $ 2,691,107   $ 728,093  
           

Number of projects with wells in progress that have been capitalized less than one year

    3     3  
           

Note 5—Common Stock

        On July 14, 2008, the Company filed a Registration Statement on Form S-3 with the SEC. Under this registration statement, which was declared effective on July 24, 2008, we may from time to time offer and sell common stock and debt securities that may be fully and unconditionally guaranteed by all of our subsidiaries for up to $150 million.

        In August 2008, the Company issued 6,820,000 common shares in a public offering for gross proceeds of $18,755,000. The Company paid $1,283,511 in commissions and expenses. The net proceeds were used primarily for drilling and completion activities on the Company's leases in the Bakken oil play located in Dunn County, North Dakota and for other general corporate activities.

        In May 2009, the Company entered into agreements to sell 9,600,000 shares of our common stock to certain institutional investors, in a non-brokered registered direct offering. The aggregate gross proceeds from the offering were $7,200,000. The Company paid $107,825 in expenses related to the offering. The net proceeds were used principally for drilling and completion activities on our leases in the Bakken oil play located in Dunn County, North Dakota and for other general corporate activities.

        In October 2009, the Company issued 13,800,000 shares of common stock in a public offering for gross proceeds of $30,360,000. The Company paid $1,721,053 in expenses related to the offering. The

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—Common Stock (Continued)


net proceeds will be used principally for drilling and completion activities on the Company's leases in the Bakken and Three Forks oil play located in Dunn County, North Dakota and for other general corporate activities.

Note 6—Compensation Plan

Stock-based Compensation Plan

        In 2007 the Company adopted the 2007 Stock Incentive Plan (the "2007 Plan"), which replaced the Incentive Share Option Plan (the "Pre-existing Plan"). The 2007 Plan authorizes it to issue stock options, stock appreciation rights (SARs), restricted stock and restricted stock units, performance awards, stock or property, stock awards and other stock-based awards may be granted to any employee, consultant, independent contractor, director or officer of the Company. A total of 8,000,000 shares of common stock may be issued under the 2007 Plan, which includes shares issuable under the Pre-existing Plan pursuant to options outstanding as of the effective date of the 2007 Plan. No more than 8,000,000 shares may be used for stock issued pursuant to incentive stock options and the number of shares available for granting restricted stock and restricted stock units shall not exceed 1,000,000, subject to adjustment as defined in the 2007 Plan. The Company granted 1,150,000 stock options and no shares of restricted stock in 2009. As of December 31, 2009, the Company has outstanding options to purchase 5,585,000 common shares at prices from $0.36 to $6.26.

        For the years ended December 31, 2009, 2008 and 2007, the Company recorded stock-based compensation of $3,428,884, $3,551,433, and $2,452,291 respectively.

        The following assumptions were used for the Black-Scholes model to calculate the stock-based compensation expense for the years presented:

 
  For the Periods Ended  
 
  December 31, 2009   December 31, 2008   December 31, 2007  

Risk free rates

    1.24 - 1.34 %   1.60 - 4.53 %   4.46 - 5.89 %

Dividend yield

    0 %   0 %   0 %

Expected volatility

    107.01 - 108.93 %   54.37 - 104.22 %   53.45 - 56.26 %

Weighted average expected stock option life

    2.97 years     4.98 years     5.86 years  

The weighted average fair value at the date of grant for stock options granted is as follows:

                   

Weighted average fair value per share

  $ 0.77   $ 1.08   $ 3.33  

Total options granted

    1,150,000     2,296,000     2,044,000  

Total weighted average fair value of options granted

  $ 865,433   $ 2,147,541   $ 6,800,579  

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—Compensation Plan (Continued)

        A summary of the stock options outstanding is as follows:

 
  Number
of Options
  Weighted
Average
Exercise
Price
 

Balance outstanding at December 31, 2007

    6,112,000   $ 3.25  
 

Granted

    2,296,000     1.96  
 

Canceled

    (588,001 )   4.40  
 

Exercised

    (312,500 )   0.58  
           

Balance outstanding at December 31, 2008

    7,507,499   $ 2.87  
 

Granted

    1,150,000     1.18  
 

Canceled

    (1,946,999 )   4.65  
 

Expired

    (775,000 )   0.45  
 

Exercised

    (350,500 )   0.95  
           

Balance outstanding at December 31, 2009

    5,585,000   $ 2.36  
           

Options exercisable at December 31, 2009

    3,493,500   $ 2.76  
           

        At December 31, 2009, stock options outstanding are as follows:

Exercise Price
  Number of Shares   Weighted Average
Remaining Contractual
Life (Years)
 

$0.36 - $1.00

    653,000     8.99  

$1.01 - $2.00

    1,900,000     2.95  

$2.01 - $3.00

    350,000     7.31  

$3.01 - $4.00

    2,177,000     3.77  

$4.01 - $5.00

    190,000     1.49  

$5.01 - $6.26

    315,000     7.39  
           

    5,585,000     4.45  
           

        The aggregate intrinsic value of both outstanding and vested options as of December 31, 2009, was $3,275,080, based on the Company's December 31, 2009 closing common stock price of $2.22. This amount would have been received by the option holders had all option holders exercised their options and sold their shares received as of that date. The total grant date fair value of the shares vested during 2009 was $3,381,216. As of December 31, 2009, there was $1,076,993 of total unrecognized compensation cost related to unamortized options. That cost is expected to be recognized over a period of three years.

        The Company did not grant or cancel restricted stock awards in 2009. All awards issued in previous years vest on a graded-vesting basis of one-third at each anniversary date over a three year service period. The Company recognizes compensation cost over the requisite service period for the entire award with the expense recognized upon vesting. The fair value of restricted stock grants is based on the stock price on the grant date and the Company assumes no annual forfeiture rate. As of December 31, 2009, there were 23,000 unvested shares with a weighted-average grant date fair value of $3.66 per share and $56,800 of total unrecognized compensation cost related to non-vested restricted stock which is expected to be recognized over a two-year period.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7—Commitments and Contingencies

        The Company leases office facilities under an operating lease agreement that expires on June 30, 2012. Rent expense was $248,621 in 2009, $243,791 in 2008, and $144,298 in 2007. The Company has no other material capital leases and no other operating lease commitments.

        The following table shows the annual rentals per year for the life of the lease:

Years ending on December 31,
   
 

2010

    289,997  

2011

    303,171  

2012

    154,172  
       

Total

  $ 747,340  
       

        During the second quarter of 2008, the Company entered into contracts for the use of two new-build drilling rigs. The first rig was placed into operation in November 2008 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior the fourth quarter of 2010. The Company intends to continue to utilize this rig in its drilling operations on the FBIR. The estimated termination fee for the first rig is approximately $3.5 million as of December 31, 2009. Under the terms of the drilling rig contract for the second rig (the "Second Rig Contract"), the Company was initially scheduled to take delivery of the second rig in February 2009 but, effective August 2009, the Company and the contractor have agreed to an amendment to the Second Rig Contract to defer such delivery in exchange for certain consideration ("Delay Payments"). Effective December 2009, the Company and the contractor further amended the Second Rig Contract whereby the Company will take delivery of the second rig in the first quarter of 2010 and will no longer make Delay Payments. The maximum termination fee payable by the Company would be $5.1 million, against which all of the Delay Payments made would be applied in the form of a credit.

        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.

Note 8—Credit Agreement

        On September 11, 2008, our wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., entered into a two-year, revolving, senior secured credit facility (the "Credit Facility") with Bank of the West, NA. While the agreement has a stated value of $20 million, borrowings are limited to a borrowing base, which was $1.625 million at December 31, 2009.

        As of December 31, 2009, we had no outstanding borrowings under the Credit Agreement and we had $209,899 in commercial letters of credit outstanding, which is considered usage for purposes of calculating availability and commitment fees. We capitalized $49,809 in deferred financing costs related to the institution of the Credit Facility, which is amortized on a straight line basis over the term of the Credit Facility. Subsequent to December 31, 2009, the Company terminated its Credit Agreement with Bank of the West, NA.

        Borrowings made under the Credit Facility were guaranteed by the Company and secured by mortgages on substantially all of our producing oil and gas properties. The Credit Facility also provided for letters of credit that may be used for general corporate purposes. Our aggregate borrowings and

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 8—Credit Agreement (Continued)


outstanding letters of credit under the Credit Facility may not, at any time, exceed the borrowing base. Interest on borrowings under the Credit Agreement accrues at variable interest rates, at our election, at either:

    (i)
    the prime rate plus a margin of 0.0% to 0.25% based on borrowing base utilization; or

    (ii)
    LIBOR plus a margin of 1.50% to 2.00% based on borrowing base utilization.

        In addition, an unused line fee of 0.5%, based on the percentage of borrowing base utilized, will accrue on the unused portion of the commitments under the Credit Facility. The Credit Facility requires us to comply with financial covenants that require us to maintain (1) a Current Ratio (defined as current assets plus unused availability under the Credit Agreement divided by current liabilities excluding any mark-to-market assets or liabilities that may occur due to the Company's hedging activities), determined at the end of each quarter, of not less than 1:1; and (2) a interest coverage ratio of trailing twelve month adjusted EBITDA to interest of not less than 3:1; and (3) a total funded debt to tangible net worth ratio of not more than 2:1. The Credit Facility contains additional representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to: (i) limitations on liens and incurrence of debt covenants; (ii) limitations on investment covenants and (iii) limitations on reorganizations, recapitalizations, liquidations, dissolutions, mergers and other combination covenants. Any outstanding principal balance of the revolving loan, together with any unpaid fees and expenses relating thereto, will be due and payable no later than September 11, 2010. As of December 31, 2009, the Company was in compliance with its covenants under the Credit Facility.

        Kodiak Oil & Gas (USA) Inc. ("Kodiak USA"), a wholly-owned subsidiary of Kodiak Oil & Gas Corporation (the "Company"), entered into an ISDA Master Agreement (the "Agreement"), dated September 30, 2008, with Bank of the West, under which the Company may enter into hedging transactions designed to protect against changes in interest rates, currency exchange rates, and fluctuations in the price of oil, gas, hydrocarbons or other commodities. Kodiak USA's obligations under the Agreement are secured by a Mortgage, Security Agreement, Assignment, Financing Statement and Fixture Filing dated as of September 11, 2008. The Company is a guarantor of Kodiak USA's obligations under the Agreement and the Agreement is cross-defaulted with Kodiak USA's revolving credit facility with Bank of the West. The Credit Facility and the ISDA Master Agreement were terminated in March 2010.

Note 9—Benefit Plans

401(k) Plan

        In 2008 the Company established a 401(k) plan for the benefit of its employees. Eligible employees may make voluntary contributions not exceeding statutory limitations to the plan. The Company matches 100% of employee contributions up to 3% of the employee's salary and 50% of an additional 2% of employee contributions. Employees are vested 100% for all contributions upon participation. The matching contribution recorded in 2009 and 2008 respectively was $61,224 and $74,696.

Other Company Benefits

        The Company provides a health, dental, vision, life, and disability insurance benefit to all regular full-time employees paid to a maximum of $500 per month per employee.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Income Taxes

        Significant components of the Company's future tax assets and liabilities, after applying enacted corporate income tax rates, are as follows:

 
  2009   2008   2007  

Future income tax assets:

                   

Net tax losses carried forward

  $ 34,201,010   $ 27,694,637   $ 13,315,114  

Stock-based compensation

    3,964,064     2,951,654     1,792,234  

Exploration and development expenses

    (1,506,168 )   6,119,821     1,267,766  

Other

    210,280     (317,416 )   (298,716 )
               

    36,869,186     36,448,696     16,076,398  

Valuation allowance for future income tax assets

  $ (36,869,186 ) $ (36,448,696 ) $ (16,076,398 )
               

Future income tax asset, net

  $   $   $  
               

        In assessing the realizability of the deferred tax assets, management considers whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which the use of such net operating losses are allowed. Among other items, management considers the scheduled reversal of deferred tax liabilities, tax planning strategies and projected future taxable income.

        The Company has available a cumulative net operating loss of approximately $97.3 million that may be carried forward to reduce taxable income in future years, which will begin expiring in 2021.

        A reconciliation of the provision (benefit) for income taxes computed at the statutory rate:

 
  2009   2008   2007  

Federal

    35.0 %   35.0 %   35.0 %

State

    1.8 %   2.1 %   2.8 %

Permanent differences

    (7.2 )%   (0.2 )%   (2.8 )%

True-up, rate change and other

    (13.2 )%   (0.8 )%   0.0 %

Valuation allowance

    (16.4 )%   (36.1 )%   (35.0 )%
               

Net

    0.0 %   0.0 %   0.0 %
               

        The Company adopted the uncertainty provision of FASB ASC Topic 740, "Income Taxes" on January 1, 2007, and has analyzed filing positions in all of the federal and state jurisdictions where it is required to file income tax returns, as well as all open tax years in these jurisdictions. These uncertain tax positions relate primarily to timing differences and management does not believe any such uncertain tax positions will materially impact the Company's effective tax rate in future periods. The Company anticipates that none of the uncertain tax positions will be recognized within the next twelve months. Our policy is to recognize any interest and penalties related to the unrecognized tax benefits in income tax expense. However, we did not accrue interest or penalties at December 31, 2009 or 2008, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax and we believe that we are below the minimum statutory threshold for imposition of penalties. We do not expect that the total amount of unrecognized tax benefits will

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 10—Income Taxes (Continued)

significantly increase or decrease during the next 12 months. In our major tax jurisdictions, the earliest years remaining open to examination are as follows: US—2004.

        The components of income taxes related to Canadian operations were not significant to the net tax assets or rate reconciliation.

Note 11—Differences Between Canadian and United States Accounting Principles

        These financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America which differ in certain respects with those principles and practices that the Company would have followed had its financial statements been prepared in accordance with accounting principles and practices generally accepted in Canada. Management does not believe the financial statements would vary materially had they been prepared in accordance with Canadian GAAP or that any recently issued, not yet effective, Canadian accounting standards if currently adopted could have a material effect on the accompanying financial statements.

Note 12—Subsequent Event

Commodity Derivative Agreement

        In February 2010, the Company entered into its first commodity derivative contract. The Company utilized a "no premium" collar to hedge the effect of price changes on a portion of its future oil production. The objective of the Company's hedging activity and the use of derivative financial instruments is to achieve more predictable cash flows. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. As the Company develops its hedging strategy, it 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 the Company's existing positions and use the proceeds from such transactions to secure additional contracts for periods in which the Company believes it has additional commodity price risk.

        The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contract is currently with a single counterparty. The Company has netting arrangements with the counterparty that provides for the offset of payables against receivables from separate derivative arrangements with that counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

        Our commodity derivative contract entered into during February 2010 is summarized below:

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

Collar

  BP North America   NYMEX     200   $70.00/$90.00     Mar 1 - Dec 31, 2010  

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 13—Quarterly Financial Information (Unaudited):

        The Company's quarterly financial information for fiscal 2009 and 2008 is as follows:

 
  First
Quarter
  Second
Quarter
  Third
Quarter
  Fourth
Quarter
 

Year Ended December 31, 2009

                         

Total revenue

  $ 791,360   $ 2,013,030   $ 3,739,329   $ 4,793,991  

Revenue from oil and gas operations

    777,733     1,990,137     3,732,158     4,777,030  

Gross profit (loss)(a)

    273,864     1,114,009     1,941,492     2,568,877  

Net income (loss)

    (1,627,607 )   (538,154 )   (9,040 )   (388,497 )

Basic and diluted net loss per share

  $ (.02 ) $ (.01 ) $ (0.00 ) $ (0.00 )

Year Ended December 31, 2008

                         

Total revenue

  $ 1,961,537   $ 2,000,690   $ 1,782,351   $ 1,220,212  

Revenue from oil and gas operations

    1,878,171     1,963,806     1,743,884     1,182,742  

Gross profit(a)

    (202,079 )   (105,589 )   (332,736 )   (341,649 )

Net income (loss)

    (2,632,036 )   (1,898,441 )   (17,959,649 )   (34,007,938 )

Basic and diluted net loss per share

  $ (.03 ) $ (.02 ) $ (0.20 ) $ (0.37 )

(a)
Excludes interest revenue, asset impairment expense, and general and administrative expense, and (gain) on currency exchange.

Note 14—Supplemental Oil and Gas Reserve Information (Unaudited)

        In January 2010, the FASB issued an ASU to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules discussed in note 2. The significant revisions involve revised definitions of oil and gas producing activities, changing the pricing used to estimate reserves at period end to a twelve month arithmetic average of the first day of the month prices and additional disclosure requirements. In contrast to the SEC rule, the FASB does not permit the disclosure of probable and possible reserves in the supplemental oil and gas information in the notes to the financial statements. The amendments are effective for annual reporting periods ending on or after December 31, 2009. Application of the revised rules is prospective and companies are not required to change prior period presentation to conform to the amendments. Application of the amended guidance has only resulted in changes to the prices used to determine proved reserves at December 31, 2009, which did not result in a significant change to the Company's proved oil and natural gas reserve volumes. The new guidelines have expanded the definition of proved undeveloped reserves that can be recorded from an economic producer. The opportunity to prove reasonable certainty for spacing areas located more than one direct development spacing area from economic producer did not impact or prove undeveloped reserves.

        The Company follows the guidelines prescribed in ASC Topic 932 for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality, and basis differentials, to the year-end estimated quantities of oil and gas to be produced in the future. The resulting future net cash flows are reduced to present value amounts by applying a ten percent annual discount factor. Future operating costs are determined based on estimates of expenditures to be incurred in producing the proved oil and gas reserves in place at the end of the period using year-end costs and assuming continuation of existing economic conditions, plus

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 14—Supplemental Oil and Gas Reserve Information (Unaudited) (Continued)


Company overhead incurred. Future development costs are determined based on estimates of capital expenditures to be incurred in developing proved oil and gas reserves.

        The assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC. These assumptions do not necessarily reflect the Company's expectations of actual revenues to be derived from those reserves, nor their present value. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these reserve quantity estimates are the basis for the valuation process. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. All of the Company's proved reserves are located in the continental United States.

        The following reserve quantity and future net cash flow information for 2009 and 2008 was prepared by Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum engineers. The 2007 information was prepared by the Company and audited by NSAI. The information for 2006 was prepared by NSAI.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 14—Supplemental Oil and Gas Reserve Information (Unaudited) (Continued)

        The following table sets forth information for the years ended December 31, 2009, 2008 and 2007 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves:

 
  Crude Oil
(Bbls)
  Natural Gas
(Mcf)
 

December 31, 2006

    532,902     2,402,433  
 

Revisions of previous estimates

    7,128     (1,089,893 )
 

Purchase of reserves

         
 

Extensions, discoveries, and other additions

    495,954     1,616,247  
 

Sale of reserves

         
 

Production

    (103,953 )   (232,635 )
           

December 31, 2007

    932,031     2,696,152  
 

Revisions of previous estimates

    (443,563 )   (556,350 )
 

Purchase of reserves

         
 

Extensions, discoveries, and other additions

    39     19,582  
 

Sale of reserves

    (80,467 )   (731,539 )
 

Production

    (63,595 )   (209,835 )
           

December 31, 2008

    344,445     1,218,010  
 

Revisions of previous estimates

    (104,059 )   (339,481 )
 

Purchase of reserves

         
 

Extensions, discoveries, and other additions

    3,775,017     3,293,648  
 

Sale of reserves

    (16,101 )   (103,244 )
 

Production

    (182,558 )   (220,455 )
           

December 31, 2009

    3,816,744     3,848,478  
           

Proved Developed Reserves, included above:

             
 

Balance, December 31, 2006

    493,300     2,399,400  
           
 

Balance, December 31, 2007

    623,950     2,455,661  
           
 

Balance, December 31, 2008

    344,445     1,218,010  
           
 

Balance, December 31, 2009

    1,170,435     1,454,904  
           

Proved Undeveloped Reserves, included above:

             
 

Balance, December 31, 2006

    39,602     3,033  
           
 

Balance, December 31, 2007

    308,081     240,491  
           
 

Balance, December 31, 2008

         
           
 

Balance, December 31, 2009

    2,646,309     2,393,574  
           

        As of December 31, 2009, we had estimated proved reserves of 3.8 million barrels ("MBbls") of oil and 3.8 billion cubic feet ("BCF") of natural gas and with a present value discounted at 10% of $39.1 million. Our reserves are are comprised of 86% crude oil and 14% natural gas on an energy equivalent basis.

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KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 14—Supplemental Oil and Gas Reserve Information (Unaudited) (Continued)

        The following values for the 2009 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31, 2009 natural gas price of $3.02 per MMBtu (Questar Rocky Mountains price) or $3.95 per MMBtu (Northern Ventura price) and crude oil price of $61.08 per barrel (West Texas Intermediate price). The values for the 2008 reserves are based on the year end December 31, 2008 natural gas price of $4.49 per MMBtu (Questar Rocky Mountains price) or $5.88 per MMBtu (Northern Ventura price) and crude oil price of $41.00 per barrel (West Texas Intermediate price). All prices are then further adjusted for transportation, quality and basis differentials.

        The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in ASC Topic 932:

 
  Year Ended December 31,  
 
  2009   2008   2007  

Future oil and gas sales

  $ 211,632,300   $ 12,881,600   $ 95,071,835  

Future production costs

    (56,591,900 )   (5,449,600 )   (22,127,559 )

Future development costs

    (45,911,300 )   (218,800 )   (10,669,553 )

Future net cash flows

    109,129,100     7,213,200     62,274,723  

10% annual discount

    (70,066,300 )   (1,885,100 )   (26,080,552 )
               

Standardized measure of discounted future net cash flows

  $ 39,062,800   $ 5,328,100   $ 36,194,171  
               

        The principle sources of change in the standardized measure of discounted future net cash flows are:

 
  Year ended December 31,  
 
  2009   2008   2007  

Balance at beginning of period

  $ 5,328,100   $ 36,194,171   $ 19,589,800  

Sales of oil and gas, net

    (9,056,676 )   (3,190,023 )   (6,059,632 )

Net change in prices and production costs

    4,178,252     (27,083,680 )   10,126,811  

Net change in future development costs

        5,666,286     (8,068,070 )

Extensions and discoveries

    42,816,413     289,066     15,524,174  

Sale of reserves

    (364,780 )   (2,029,543 )    

Revisions of previous quantity estimates

    (1,611,134 )   (12,231,173 )   (5,356,105 )

Previously estimated development costs incurred

        3,094,691     8,742,935  

Net change in income taxes

             

Accretion of discount

    432,635     4,546,617     1,537,322  

Other

    (2,660,010 )   71,688     156,936  
               

Balance at end of period

  $ 39,062,800   $ 5,328,100   $ 36,194,171  
               

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ITEM 9.    CHANGES IN AND DISAGRE