Annual Reports

 
Quarterly Reports

 
8-K

 
Other

Kodiak Oil 10-K 2010

QuickLinks -- Click here to rapidly navigate through this document

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



FORM 10-K/A
Amendment No. 1

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.



EXPLANATORY NOTE

        This Amendment No. 1 on Form 10-K/A (the "Amendment No. 1") amends our Annual Report on Form 10-K for the fiscal year ended December 31, 2009, originally filed on March 11, 2010 (the "2009 Form 10-K"). We are filing this Amendment No. 1 in response to certain comments made by the staff of the Securities and Exchange Commission (the "SEC"). In response to such comments, we have amended and restated the following items:

    Part I, Items 1 and 2. Business and Properties, to include additional information under the headings "Production, Average Sales Prices, and Production Costs," in respect of our oil and gas production from the Bakken formation field and from our other fields combined, as well as in total, (ii) "Our Reserves" in respect of the change in our proved developed reserves from 2008 to 2009 resulting primarily from our exploration program related to our Bakken properties, and (iii) "Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used" in respect of the qualifications of our reserves manager, Chief Operating Officer and President and their role in the reserves estimation process;

    Part II, Item 6. Selected Consolidated Financial Information, to include additional information under the heading "Non-GAAP Financial Measure" in respect of our reasons for using and use of Adjusted EBITDA; and

    Part II, Item 8. Financial Statements and Supplementary Data, to include additional information in (i) Note 2-Basis of Presentation and Significant Accounting Policies, under the heading "Oil and Gas Producing Activities," in respect of the effect of estimated future income tax in calculating the full cost ceiling test, and (ii) Note 14—Supplemental Oil and Gas Reserve Information (Unaudited) in respect of the change in our proved developed reserves from 2008 to 2009 resulting primarily from our exploration program related to our Bakken properties, and in respect of the effect of estimated future income tax in calculating the standardized measure of discounted future net cash flows.

        Additionally, we are filing an amended and restated reserve estimate report of Netherland Sewell & Associates, Inc., which was filed as Exhibit 99.1 to the 2009 Form 10-K.

        We are also filing currently dated certifications of our Chief Executive Officer and Chief Financial Officer, as required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002, and currently dated consents of Hein & Associates LLP and Netherland Sewell & Associates, Inc.

        No item of or disclosures appearing in our 2009 Form 10-K are affected by this filing other than the items and exhibit described above. This report on Form 10-K/A is presented as of the filing date of the 2009 Form 10-K and does not reflect events occurring after that date, or modify or update disclosures in any way.

        Unless otherwise indicated, references to "we," "us," "Company," or "Kodiak" mean Kodiak Oil & Gas Corp. and its subsidiaries, and references to "fiscal" mean the Company's fiscal year ended December 31 for fiscal years 2009, 2008 and 2007.

2



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.

3


        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

4



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.

5


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.

6


        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 ended December 31, 2009. Our oil revenues are derived primarily from eighteen wells that we operate

7



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  

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  

        The Bakken formation is the only field (as such term is used within the meaning of applicable regulations of the SEC) that contains more than 15% of our total proved reserves. At December 31, 2009, this field contained 96% of our total proved reserves, nearly all of which are located in Dunn County, North Dakota. The following table discloses our oil and gas production from the Bakken formation field and from our other fields combined, as well as in total, for the periods indicated:

 
  2009   2008   2007  
 
  Bakken
Formation
  Other   Total   Bakken
Formation
  Other   Total   Bakken
Formation
  Other   Total  

Sales Volume:

                                                       
 

Gas (Mcf)

    6,092     214,363     220,455     6,370     203,445     209,815     17,627     182,564     200,191  
 

Oil (Bbls)

    145,181     37,377     182,558     18,733     44,862     63,595     45,793     57,121     102,914  
 

Production volumes (BOE)

    146,196     73,104     219,300     19,794     78,770     98,564     48,731     87,548     136,279  

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

8



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.

        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.

9


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 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.

10


        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 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

11



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

12



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. The change in our proved developed reserves from 2008 to 2009 was primarily due to our exploration program related to our Bakken properties in Dunn County, North Dakota. Specifically, during 2009, $26.5 million of our total capital expenditures of $27.4 million was spent in connection with the drilling of 11 exploratory Bakken wells, of which 9 gross (4.8 net) wells were completed and turned to production. These wells constituted 996.1 MBbls of the total 1,170.4 MBbls of proved developed oil reserves at December 31, 2009 and accounted for substantially all of the increase from December 31, 2008 in proved developed oil reserves.

        We had no proved undeveloped reserves at December 31, 2008. Thus, all proved undeveloped reserves are less than one year old. Primarily as a result of the 2009 exploratory drilling activity described in the preceding paragraph, we converted oil and gas resources under undeveloped acreage to 2,646.3 MBbls of proved undeveloped reserves. Drilling operations with respect to all of these proved undeveloped locations are included in the Company's 2010 drilling budget. 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. To ensure accuracy and completeness of the data prior to submission to NSAI, the information we provide is reviewed by the following persons with the following qualifications:

    Senior Reservoir Engineer, Wally O'Connell: Mr. O'Connell, a Registered Professional Engineer, is our reserves manager and has over 35 years of experience in the oil and gas industry in the areas of engineering and reserves management. He has worked for us since 2007 in the role of reserves manager. Prior to such time, he served as Exploitation Manager-Wattenberg Area for both Anadarko Petroleum Corporation from 2006 to 2007 and Kerr-McGee Rocky Mountain Corporation from 1998 to 2006. Prior to such time, he served in a variety of lead reservoir and petroleum engineering positions at various companies, including Questa Engineering Corporation, Whiting Petroleum Corporation and Nicor Exploration Company. He received a Bachelor of Science in Petroleum Engineering from Montana College of Mineral Science and Technology in 1972.

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

    President and Chief Executive Officer, Lynn Peterson: Mr. Peterson has approximately 30 years of experience in the oil and gas industry. He has served as a director of the Company since November 2001 and President and Chief Executive Officer since July 2002. He was an owner of CP Resources, LLC, an independent oil and natural gas company, from 1986 to 2001.

13


      Mr. Peterson served as Treasurer of Deca Energy from 1981 to 1986. Mr. Peterson was employed by Ernst and Whinney as a certified public accountant prior to this time. He received a Bachelor of Science in Accounting from the University of Northern Colorado in 1975.

        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.

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.

14


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 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.

15


        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. 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

16



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.

17



PART II

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

18



expense, (ii) income taxes, (iii) depreciation, depletion and amortization, (iv) impairment (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. 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. Management believes that Adjusted EBITDA is a useful supplemental disclosure regarding our financial condition and results of operations for the following reasons:

    by eliminating the effect of certain non-cash items, Adjusted EBITDA provides an indication of our ability to generate cash flow from our operations at a level that can sustain or support our ongoing operations and our capital investment program. In addition, we use Adjusted EBITDA when developing our capital investment budget, and the disclosure to investors of Adjusted EBITDA allows investors to better assess our financial condition and thus our ability to support such budget;

    a variant of Adjusted EBITDA is viewed by our lender as an indicator of our operating results and financial condition and as such, it is used in a compliance covenant under our revolving credit facility to measure our viability. In addition, Adjusted EBITDA is viewed as a determining factor in the amount of the overall borrowing capacity under our credit facility. Disclosing Adjusted EBITDA to our investors therefore provides investors with an indication of our potential borrowing base under our credit facility and our compliance with the applicable covenant, which in turn are indicators of our operating results and financial condition;

    Adjusted EBITDA is considered by our Compensation Committee to be a significant indicator of the results of our operations and as such, the Compensation Committee has determined it to be a significant component of the corporate objectives to which the vesting of senior management's equity-based awards are tied. Reporting Adjusted EBITDA therefore provides additional transparency to investors in respect of the attainment of our operational corporate objectives and our executive compensation program;

    we believe that investors benefit from having access to the same financial measures that our management team and other external users (such as our lender under our credit facility) utilize in evaluating our operational performance and financial condition; and

    Adjusted EBITDA, or a variant thereof, is commonly used by companies in the oil and gas industry as a performance measure. We and other external users use this non-GAAP performance measure to compare our performance with other companies in the industry that make a similar disclosure, and management believes that this performance measure may be useful to investors for the same purpose.

        As discussed elsewhere in this annual report on Form 10-K, we and certain third parties use our Adjusted EBITDA (or a variant thereof) for a variety of analytical purposes, including the following:

    In the development of our 2010 capital expenditure budget, we considered, among other things, Adjusted EBITDA, which is a measure of our ability to generate cash resources from our operations. Management also evaluated the 2010 projected Adjusted EBITDA to estimate that portion of our budget that could be funded from the generation of cash from our operations and, conversely, the remaining amount that would need to be funded from the combination of working capital and financing sources, such as borrowings under our credit facility or sales of additional securities.

    A variant of Adjusted EBITDA, as defined in our credit agreement that was in place at December 31, 2009, was used in a covenant calculation as a measure of our liquidity and ability to service our debt. The calculation used for the covenant was Adjusted EBITDA, as defined in

19


      the credit agreement, divided by applicable interest, as defined in the credit agreement. Under that covenant, the resulting ratio was required to be more than 3 to 1. As of December 31, 2009, we had no debt outstanding and we were therefore in compliance with the covenant. Further, because a variant of Adjusted EBITDA was used in the covenant calculation, it can be a factor to be considered by the lender when establishing our borrowing base. However, because we had no amounts outstanding under that credit agreement at any time, Adjusted EBITDA had a neutral impact on the borrowing base re-determinations.

    Our Compensation Committee considers Adjusted EBITDA, along with other corporate measures, in determining the vesting of certain equity-based awards of our executive officers. Based on the results for the year ended December 31, 2009, our Compensation Committee approved the vesting of approximately 99.5% of the total 2009 performance-based stock options granted to our executive officers. The Adjusted EBITDA component of the vesting criteria resulted in the vesting of approximately 11% of the total stock options granted. Further discussion of these awards and the determination of the vesting is available in our definitive proxy statement filed with the SEC on April 30, 2010.

        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. This information should be read in conjunction with all of our financial information, including our financial statements and our management's discussion and analysis of the Company's financial condition and results of operations, as set forth in Item 7. 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. 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 )
                       

20


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

21



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

22



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

23



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

24



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

25



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

26



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

27



KODIAK OIL & GAS CORP.

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 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.

28



KODIAK OIL & GAS CORP.

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 was 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), less any applicable future taxes. As noted under the heading "Our Reserves" in Part I of this report, as of December 31, 2009, there was no tax benefit or expense included in our ceiling test, due to the fact that future net revenues are exceeded by the tax basis of the properties involved and the Company's existing NOLs. We expect that all of our NOLs will be realized within future carryforward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets.

        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,

29



KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


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.

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.

30



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.

31



KODIAK OIL & GAS CORP.

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.

32



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.

33



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

34



KODIAK OIL & GAS CORP.

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  

35



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.

36



KODIAK OIL & GAS CORP.

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

37



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.

38



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

39



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  

40



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

41



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.

42



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. As stated elsewhere in this report, the change in our proved developed reserves from 2008 to 2009 was primarily due to our exploration program related to our Bakken properties in Dunn County, North Dakota. Specifically, during 2009, $26.5 million of our total capital expenditures of

43



KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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


$27.4 million was spent in connection with the drilling of 11 exploratory Bakken wells, of which 9 gross (4.8 net) wells were completed and turned to production. These wells constituted 996.1 MBbls of the total 1,170.4 MBbls of proved developed oil reserves at December 31, 2009 and accounted for substantially all of the increase from December 31, 2008 in proved developed oil reserves.

        We had no proved undeveloped reserves at December 31, 2008. Thus, all proved undeveloped reserves are less than one year old. Primarily as a result of the 2009 exploratory drilling activity described in the preceding paragraph, we converted oil and gas resources under undeveloped acreage to 2,646.3 MBbls of proved undeveloped reserves. Drilling operations with respect to all of these proved undeveloped locations are included in the Company's 2010 drilling budget.

        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(1)

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

(1)
Our calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses (which is zero) for all years reported. Due to the fact that future pretax net cash flows relating to our proved oil and gas reserves are exceeded by the tax basis of the properties involved and the Company's existing net operating losses ("NOLs"), there was no tax benefit or expense for all years reported. We expect that all of our NOLs will be realized within future carryforward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets.

44



KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

        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  
               

45



PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(b)
Exhibits

Exhibit
Number
  Description
  23.1   Consent of Hein & Associates LLP
  23.2   Consent of Netherland Sewell & Associates, Inc.
  31.1   Certification of the Chief Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a)
  31.2   Certification of the Chief Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a)
  32.1   Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350
  32.2   Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350
  99.1   Reserve Estimate Report of Netherland Sewell & Associates, Inc.

46



SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

    KODIAK OIL & GAS CORP.
(Registrant)

Date: August 6, 2010

 

By:

 

/s/ LYNN A. PETERSON

Lynn A. Peterson
President and Chief Executive Officer
(principal executive officer)

        Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

By:   /s/ LYNN A. PETERSON

Lynn A. Peterson
  President and Chief Executive Officer (principal executive officer)   August 6, 2010
By:   /s/ JAMES P. HENDERSON

James P. Henderson
  Chief Financial Officer, Treasurer and Secretary (principal financial officer and principal accounting officer)   August 6, 2010

By:

 

*

James E. Catlin

 

Vice President and Chief Operations Officer

 

August 6, 2010

By:

 

*

Herrick K. Lidstone, Jr.

 

Director

 

August 6, 2010

By:

 

*

Rodney D. Knutson

 

Director

 

August 6, 2010

By:

 

*

Don McDonald

 

Director

 

August 6, 2010

 

*By:   /s/ LYNN A. PETERSON

       
    Lynn A. Peterson, Attorney-in-fact   August 6, 2010

47




QuickLinks

EXPLANATORY NOTE
PART I
Kodiak Oil & Gas Corp. Drilling and Completion Activities
Longer Laterals (8,000' to 10,000')
Shorter Laterals (4,000' to 7,000')
PART II
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
KODIAK OIL & GAS CORP. CONSOLIDATED BALANCE SHEETS
KODIAK OIL & GAS CORP. CONSOLIDATED STATEMENTS OF OPERATIONS
KODIAK OIL & GAS CORP. STATEMENTS OF STOCKHOLDERS' EQUITY
KODIAK OIL & GAS CORP. CONSOLIDATED STATEMENTS OF CASHFLOWS
KODIAK OIL & GAS CORP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PART IV
SIGNATURES
Wikinvest © 2006, 2007, 2008, 2009, 2010, 2011, 2012. Use of this site is subject to express Terms of Service, Privacy Policy, and Disclaimer. By continuing past this page, you agree to abide by these terms. Any information provided by Wikinvest, including but not limited to company data, competitors, business analysis, market share, sales revenues and other operating metrics, earnings call analysis, conference call transcripts, industry information, or price targets should not be construed as research, trading tips or recommendations, or investment advice and is provided with no warrants as to its accuracy. Stock market data, including US and International equity symbols, stock quotes, share prices, earnings ratios, and other fundamental data is provided by data partners. Stock market quotes delayed at least 15 minutes for NASDAQ, 20 mins for NYSE and AMEX. Market data by Xignite. See data providers for more details. Company names, products, services and branding cited herein may be trademarks or registered trademarks of their respective owners. The use of trademarks or service marks of another is not a representation that the other is affiliated with, sponsors, is sponsored by, endorses, or is endorsed by Wikinvest.
Powered by MediaWiki