UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington 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 250Denver, 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 RegisteredCommon Stock

NYSE Amex


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

Title of Each ClassN/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:



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

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PART I

ITEMS 1 AND 2.    BUSINESS AND PROPERTIES

Overview and Strategy

Kodiak Oil & Gas Corp. ("Kodiak," "we" or the "Company") is an independent energy company focused on the exploration,
exploitation, acquisition and production of crude oil and natural gas in the United States. Our oil and natural gas reserves and operations are primarily concentrated in two Rocky Mountain basins, the
Williston Basin of North Dakota and Montana and the Green River Basin of Wyoming and Colorado. Kodiak's corporate strategy is to internally identify prospects, acquire lands encompassing those
prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved
reserves, as well as development and exploratory drilling opportunities on high potential non-conventional and conventional oil and
natural gas prospects that we have the opportunity to explore, drill and develop. Significant prospects in our portfolio currently include:

Williston Basin



Green River Basin / Big Horn Basin / Powder River Basin



3

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

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

For
a summary of certain financial information of the Company, including information on loss and total assets, see Item 6"Selected Consolidated Financial
Information."

Capital Budget

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

The
2010 capital expenditure budget, both as to amount and allocation, is subject to market conditions, oilfield services and equipment availability, commodity prices and drilling
results. While we continue to explore opportunities to expand our acreage position, our current budget is primarily allocated to drilling and completing wells. If we identify acreage that meets our
strategic requirements, we may re-allocate our capital expenditure budget to permit us to complete a potential acreage acquisition. Alternatively, depending on the availability and terms
of capital resources that may be available to us, we may increase our capital expenditure budget to allow us to acquire additional acreage. We expect to fund our capital budget primarily from cash on
hand, anticipated cash flow from operations and borrowings under a potential reserve-based revolving line of credit that we anticipate will be available to us in the second quarter of 2010. If our
existing and potential sources of liquidity are not sufficient to undertake our planned or revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties,
sell interest in one or more of our properties or sell common shares. There can be no assurance that any such transactions can be completed or that such transactions will satisfy our operating capital
requirements. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our planned
expenditures or restructure our operations, and we would be unable to implement our original exploration and drilling program.

Drilling and Completion Operations in Dunn County, North Dakota

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

4

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

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

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

Kodiak Oil & Gas Corp. Drilling and Completion Activities

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

Well

WI / NRI
(%)

Days to
TD*

Length of
Lateral

Completion
Date

Number of
Stages

IP 24-Hour
Test BOE/D

First 30 Day
BOE
Production

StatusTSB #16-8-7H


37.5 / 30.5


28


8.995'

6/7/2009


15


1,856


23,874

Flowing wellTSB #14-33-28H


50 /41


31


8,313'

8/3/2009


15


1,492


21,400

Flowing wellCE #1-22-10H


55 /45


32


9,949'

10/18/2009


15


1,288


15,510

Flowing wellTB #16-15-16H


60 /50


25


9,442'

12/7/2009


19


100


1,569

Waiting on pumpMC #13-34-28-2H


57.5 /46.5


35


9,769'

Q210










Waiting completionMC #13-34-28-1H


57.5 /46.5





8,600'
**
Q210










DrillingTSB #14-21-33-16H


50 /41


















Spud after MC PadTSB #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 pumpMC #16-34H


60 / 49


36


4,150'

5/4/2009


5


1,394


14,720

On pumpTSB #16-8-16H


50 /41


31


4,465'

6/18/2009


5


811


12,758

Flowing wellTSB #14-33-6H


50 /41


26


4,163'

8/24/2009


6


978


13,608

Flowing wellCE #1-22-23H


60 /50


19


6,620'

10/18/2009


13


845


11,916

Flowing wellMC #16-3-11H


60 /49


38


4,729'

2/12/2010


12


1,419




Flowing wellMC #16-3H


60 /49


19


4,188'

3/2/2010


9


1,495




Flowing wellMC #13-34-3H


60 /49


22


4,330'

Q210


11







Waiting completionTSB #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

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Property Acquisition and Exploration Activities

In the Williston Basin, as of December 31, 2009, we owned an interest in approximately 98,000 gross acres and 60,000 net acres.
The primary targets within the Basin are the Mission Canyon, Bakken, Three Forks and Red River Formations, as well as other formations that produce in the Basin. We owned approximately 55,000 gross
acres and 35,000 net acres on the FBIR with most of these lands acquired in previous years. The majority of our lands in this prospect area are held in trust and are administered by the Bureau of
Indian Affairs (BIA) on behalf of the individual members of the Three Affiliated Tribes Fort Berthold Indian Reservation. Typically these lands are acquired through private negotiations with the
individual land owners and the Three Affiliated Tribes and have a primary lease term of five years. In most cases we have two to four years remaining on the primary lease term of these leases.
Approximately 30% of these lands are encompassed within federal operating units approved by the U.S. Bureau of Land Management ("BLM") that allow for the orderly exploration and development. The land
owner typically retains an 18% landowner royalty. In most cases, these lands require an annual delay rental of $2.50 per net acre.

Our
acreage located in the Williston Basin outside of the FBIR is held primarily on the basis of fee and federal leases. These leases typically carry a primary term of three to ten years
with landowner royalties of 12.5% to 18.5%. In most cases we obtain "paid up" fee leases that do not require annual delay rentals. The federal lands require annual delay rentals of $1.50 to $2.00 per
net acre.

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

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

6

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The
following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of December 31, 2009.

Undeveloped
Acreage(1)

Developed
Acreage(2)

Total
AcreageGross

Net

Gross

Net

Gross

NetGreen River BasinWyoming


42,555


9,770


1,520


908


44,075


10,678Colorado


7,339


4,960


0


0


7,339


4,960Williston BasinMontana


27,640


16,806


800


400


28,440


17,206North Dakota


62,405


38,519


7,200


3,992


69,605


42,511Other BasinsWyoming


12,362


10,675


0


0


12,362


10,675Acreage 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 AcreageYear Ending

Gross

NetDecember 31, 2010


27,930


16,714December 31, 2011


6,471


3,570December 31, 2012


29,295


17,096Total


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

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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

2007Price:Gas ($/Mcf)

$
2.84

$
6.54

$
5.26Oil ($/Bbls)

$
58.35

$
84.86

$
65.72Production costs ($/BOE):Lease operating expenses

$
4.25

$
28.78

$
6.87Production and property taxes

$
5.50

$
6.54

$
5.30Gathering, 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

2007Bakken
Formation

Other

Total

Bakken
Formation

Other

Total

Bakken
Formation

Other

TotalSales Volume:Gas (Mcf)


6,092


214,363


220,455


6,370


203,445


209,815


17,627


182,564


200,191Oil (Bbls)


145,181


37,377


182,558


18,733


44,862


63,595


45,793


57,121


102,914Production 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

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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 BasinMission Canyon/Red River wells and related infrastructure


83


1,122Bakken wells and related infrastructure


26,450


57,100Acreage/Seismic


277


2,000Total Williston Basin

$
26,810

$
60,222WyomingVermillion 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

2007Gross

Net

Gross

Net

Gross

NetDevelopment wells, completed as:Oil wells














2


1.0Gas wells








1


0.1





Non-Productive(1)














1


0.5Exploratory wells, completed as:Oil wells


9


4.8











Gas wells














3


2.8Non-Productive(1)














4


1.8Total


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.


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Productive Wells

As part of our corporate strategy, we seek to operate our wells where possible and to maintain a high level of participation in our
wells by investing our own capital in drilling operations. The following table summarizes our productive wells as of 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

TotalGross

Net

Gross

Net

Gross

NetWilliston BasinOil and associated gas wells


18


9.5








18


9.5Wyoming/ColoradoGas wells


5


4.7


11


4.0


16


8.7Total


23


14.2


11


4.0


34


18.2


Operations in the Williston Basin of Montana and North Dakota

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

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

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

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

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

Operations in Wyoming and Colorado

Vermillion Basin DeepBaxter Shale and Frontier Sandstone

Our primary leaseholdings in the Green River Basin are located in an area referred to as the Vermillion Basin. In this geologic region,
we believe there is natural gas trapped in various sands, coals and shales at depths ranging from 2,000 feet to nearly 15,000 feet. The primary target of our current exploration efforts in this area
is the over-pressured Baxter Shale at depths to approximately 13,000 feet. As of December 31, 2009, we controlled approximately 44,000 gross (9,200 net) acres in the Vermilion
Basin.

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

Recent SEC Rule-Making Amendments

The 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:



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

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

NSAI
prepared our estimated reserves as of December 31, 2009 and December 31, 2008. The reserve estimates as of December 31, 2007 were developed using geological and
engineering data and interests and burdens information developed by the Company. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of
additional exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices, and other factors. You should read the notes following
the table below and the information following the notes to our audited financial statements for the years ended December 31, 2009 and 2008 included in Item 8. "Financial Statements and
Supplementary Data" in this Form 10-K in conjunction with the following reserve estimates:

As of December 31,2009

2008Proved Developed Oil Reserves (Thousands of Barrels, or MBbls)


1,170.4


344.4Proved Undeveloped Oil Reserves (MBbls)


2,646.3


Total Proved Oil Reserves (MBbls)


3,816.7


344.4Proved Developed Gas Reserves (Million Cubic Feet, or MMcf)


1,454.9


1,218.0Proved Undeveloped Gas Reserves (MMcf)


2,393.6


Total Proved Gas Reserves (MMcf)


3,848.5


1,218.0Total Proved Gas Equivalents (Million Cubic Feet Equivalent, or MMcfe)(1)


26,748.9


3,284.4Total Proved Oil Equivalents (Thousands of Barrels Equivalent, or MBOE)(1)


4,458.2


547.4Present 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:



13

---





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:



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:



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 athttp://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

2005Income Statement Data:Revenue

$
11,337,709

$
6,964,790

$
9,320,377

$
4,965,169

$
453,135Cost and expenses, excluding impairment


13,901,007


15,962,854


13,506,267


7,751,209


2,458,226Asset 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

2005Balance Sheet Data:Current assets

$
37,005,416

$
20,654,933

$
15,377,809

$
61,117,145

$
7,990,556Property and equipment, net


42,236,077


17,842,773


58,386,427


52,250,265


17,463,269Total assets


79,683,024


39,016,479


74,331,321


113,773,614


25,790,316Current liabilities


8,694,432


5,231,075


5,163,457


9,879,104


4,411,572Stockholders' equity

$
69,928,382

$
32,998,224

$
68,293,366

$
103,644,815

$
21,309,671Basic 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:



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:



19

---





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:



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

2005EBITDA 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


157,868Asset impairment





47,500,000


34,000,000





(Gain) / loss on foreign currency exchange


(11,327
)

36,725


(792,467
)

32,008


95,864Stock based compensation expense


3,428,884


3,551,433


2,452,291


1,527,361


541,111Adjusted 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 inInternal ControlIntegrated Frameworkissued 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,
2008ASSETSCurrent Assets:Cash and cash equivalents

$
24,885,546

$
7,581,265Accounts receivableTrade


2,562,779


1,934,818Accrued sales revenues


1,909,221


516,870Inventory, prepaid expenses and other


7,647,870


10,621,980Total Current Assets


37,005,416


20,654,933Oil and gas properties (full cost method), at cost:Proved oil and gas properties


123,259,252


97,934,058Unproved oil and gas properties


12,068,156


11,985,533Wells in progress


2,691,107


728,093Less-accumulated depletion, depreciation, amortization, accretion and asset impairment


(95,782,438
)

(92,804,911
)Net oil and gas properties


42,236,077


17,842,773Other property and equipment, net of accumulated depreciation of $284,535 in 2009 and $270,620 in 2008


441,531


272,705Restricted investments





246,068Total Assets

$
79,683,024

$
39,016,479LIABILITIES AND STOCKHOLDERS' EQUITYCurrent Liabilities:Accounts payable and accrued liabilities

$
7,742,617

$
4,125,335Advances from joint interest owners


951,815


1,105,740Total Current Liabilities


8,694,432


5,231,075Noncurrent Liabilities:Asset retirement obligation


1,060,210


787,180Total Liabilities


9,754,642


6,018,255Commitments and ContingenciesNote 7Stockholders' Equity:Common stockno par value; unlimited authorizedIssued and outstanding: 118,879,931 shares in 2009 and 95,129,431 shares in 2008Contributed surplus


175,791,301


136,297,845Accumulated deficit


(105,862,919
)

(103,299,621
)Total Stockholders' Equity


69,928,382


32,998,224Total 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

2007Revenues:Gas production

$
625,360

$
1,371,822

$
1,053,331Oil production


10,651,698


5,396,781


6,764,017Interest & other


60,651


196,187


1,503,029Total revenue


11,337,709


6,964,790


9,320,377Cost and expenses:Oil and gas production


2,220,382


3,578,580


1,757,717Depletion, depreciation, amortization and accretion


3,158,433


4,172,077


5,206,631Asset impairment





47,500,000


34,000,000General and administrative


8,522,192


8,212,197


6,541,919Total costs and expenses


13,901,007


63,462,854


47,506,267Net loss

$
(2,563,298
)
$
(56,498,064
)
$
(38,185,890
)Basic & diluted weighted-average common shares outstanding


103,688,733


90,739,316


87,742,996Basic & 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
EquityBalance December 31, 2006:


87,548,426

$
112,260,482

$
(8,615,667
)
$
103,644,815Issuance of stocks for cash:pursuant to exercise of options


363,500


382,150





382,150Employee stock grants


81,000


125,200





125,200Stock-based compensation





2,327,091





2,327,091Net loss








(38,185,890
)

(38,185,890
)Balance December 31, 2007:


87,992,926

$
115,094,923

$
(46,801,557
)
$
68,293,366Issuance 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





180,000Share issuance costs





(1,283,511
)




(1,283,511
)Employee stock grants


4,000


154,655





154,655Stock-based compensation





3,396,778





3,396,778Net loss








(56,498,064
)

(56,498,064
)Balance December 31, 2008:


95,129,431

$
136,297,845

$
(103,299,621
)
$
32,998,224Issuance 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





333,450Share issuance costs





(1,828,878
)




(1,828,878
)Stock-based compensation





3,428,884





3,428,884Net 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

2007Cash 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


5,206,631Asset impairment





47,500,000


34,000,000Asset retirement








(29,893
)Stock based compensation


3,428,884


3,551,433


2,452,291Changes in current assets and liabilities:Accounts receivabletrade


(627,961
)

(560,975
)

503,342Accounts 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
)

2,073,412Cash 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


382,150Issuance costs


(1,828,878
)

(1,283,511
)

Net cash provided by financing activities


36,064,572


17,651,489


382,150Net 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


58,469,263Cash and cash equivalents at end of the period

$
24,885,546

$
7,581,265

$
13,015,318Supplemental cash flow informationOil & gas property accrual included in Accounts payable and accrued liabilities

$
601,060

$
1,457,189

$
1,544,868Asset 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

2007Plains 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 EndedDecember 31, 2009

December 31, 2008Balance beginning of period

$
787,180

$
874,498Liabilities incurred


251,671


Liabilities settled


(74,078
)

(147,252
)Accretion expense


95,437


59,934Balance 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") issuedThe 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

2007Property Acquisition costs:Proved

$


$


$
Unproved


462,542





4,285,277Exploration costs


5,412


8,893,293


28,960,843Development costs


26,902,877


2,163,143


11,869,900Total

$
27,370,831

$
11,056,436

$
45,116,020Total 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

2008Colorado

$
125,959

$
124,656Montana


910,665


803,386North Dakota


9,994,408


10,038,305Wyoming


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 YearPrior

$
2,928,6542007


1,758,4392008


7,298,4402009


82,623Total

$
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, 2008Beginning balance

$
728,093

$
414,074Additions to capital wells in progress costs pending the determination of proved reserves


16,127,748


728,093Reclassifications 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 312009

2008Wells in progress capitalized for one year or less

$
2,465,078

$
728,093Wells in progress capitalized for one year or more


226,029


Ending balance at December 31

$
2,691,107

$
728,093Number 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 EndedDecember 31, 2009

December 31, 2008

December 31, 2007Risk 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 yearsThe 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

$
3.33Total options granted


1,150,000


2,296,000


2,044,000Total 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
PriceBalance outstanding at December 31, 2007


6,112,000

$
3.25Granted


2,296,000


1.96Canceled


(588,001
)

4.40Exercised


(312,500
)

0.58Balance outstanding at December 31, 2008


7,507,499

$
2.87Granted


1,150,000


1.18Canceled


(1,946,999
)

4.65Expired


(775,000
)

0.45Exercised


(350,500
)

0.95Balance outstanding at December 31, 2009


5,585,000

$
2.36Options 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


7.395,585,000


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


289,9972011


303,1712012


154,172Total

$
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:



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

2007Future income tax assets:Net tax losses carried forward

$
34,201,010

$
27,694,637

$
13,315,114Stock-based compensation


3,964,064


2,951,654


1,792,234Exploration and development expenses


(1,506,168
)

6,119,821


1,267,766Other


210,280


(317,416
)

(298,716
)36,869,186


36,448,696


16,076,398Valuation 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

2007Federal


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)

TermCollar

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
QuarterYear Ended December 31, 2009Total revenue

$
791,360

$
2,013,030

$
3,739,329

$
4,793,991Revenue from oil and gas operations


777,733


1,990,137


3,732,158


4,777,030Gross profit (loss)(a)


273,864


1,114,009


1,941,492


2,568,877Net 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, 2008Total revenue

$
1,961,537

$
2,000,690

$
1,782,351

$
1,220,212Revenue from oil and gas operations


1,878,171


1,963,806


1,743,884


1,182,742Gross 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


2,402,433Revisions of previous estimates


7,128


(1,089,893
)Purchase of reserves





Extensions, discoveries, and other additions


495,954


1,616,247Sale of reserves





Production


(103,953
)

(232,635
)December 31, 2007


932,031


2,696,152Revisions of previous estimates


(443,563
)

(556,350
)Purchase of reserves





Extensions, discoveries, and other additions


39


19,582Sale of reserves


(80,467
)

(731,539
)Production


(63,595
)

(209,835
)December 31, 2008


344,445


1,218,010Revisions of previous estimates


(104,059
)

(339,481
)Purchase of reserves





Extensions, discoveries, and other additions


3,775,017


3,293,648Sale of reserves


(16,101
)

(103,244
)Production


(182,558
)

(220,455
)December 31, 2009


3,816,744


3,848,478Proved Developed Reserves, included above:Balance, December 31, 2006


493,300


2,399,400Balance, December 31, 2007


623,950


2,455,661Balance, December 31, 2008


344,445


1,218,010Balance, December 31, 2009


1,170,435


1,454,904Proved Undeveloped Reserves, included above:Balance, December 31, 2006


39,602


3,033Balance, December 31, 2007


308,081


240,491Balance, 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

2007Future oil and gas sales

$
211,632,300

$
12,881,600

$
95,071,835Future 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


62,274,72310% 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

2007Balance at beginning of period

$
5,328,100

$
36,194,171

$
19,589,800Sales 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
)

10,126,811Net change in future development costs





5,666,286


(8,068,070
)Extensions and discoveries


42,816,413


289,066


15,524,174Sale 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


8,742,935Net change in income taxes








Accretion of discount


432,635


4,546,617


1,537,322Other


(2,660,010
)

71,688


156,936Balance at end of period

$
39,062,800

$
5,328,100

$
36,194,171


45

---





PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit
Number

Description23.1

Consent of Hein & Associates LLP23.2

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 135032.2

Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 135099.1

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, 2010By:

/s/ JAMES P. HENDERSON James P. Henderson

Chief Financial Officer, Treasurer and Secretary (principal financial officer and principal accounting officer)

August 6, 2010By:

* James E. Catlin

Vice President and Chief Operations Officer

August 6, 2010By:

* Herrick K. Lidstone, Jr.

Director

August 6, 2010By:

* Rodney D. Knutson

Director

August 6, 2010By:

* Don McDonald

Director

August 6, 2010




*By:

/s/ LYNN A. PETERSONLynn A. Peterson, Attorney-in-fact

August 6, 2010


47

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