Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2010

Commission File No. 001-32920

GRAPHIC

(Exact name of registrant as specified in its charter)

Yukon Territory(State or other jurisdiction
of incorporation or organization)

N/A(I.R.S. Employer
Identification No.)


1625 Broadway, Suite 250
Denver, Colorado 80202(Address of principal executive offices, including zip code)

(303) 592-8075(Registrant's telephone number, including area code)

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

Large accelerated filer o

Accelerated filer ý

Non-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o


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

119,604,910 shares, no par value, of the Registrant's common stock were issued and outstanding as of August 4, 2010.



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Table of Contents



KODIAK OIL & GAS CORP.

INDEX



PART 1FINANCIAL INFORMATION

2ITEM 1.

FINANCIAL STATEMENTS

2ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

20ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

34ITEM 4.

CONTROLS AND PROCEDURES

36PART IIOTHER INFORMATION

37ITEM 1.

LEGAL PROCEEDINGS

37ITEM 1A.

RISK FACTORS

37ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

57ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

57ITEM 4.

RESERVED

57ITEM 5.

OTHER INFORMATION

57ITEM 6.

EXHIBITS

57SIGNATURES

58


1

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Table of Contents

PART 1FINANCIAL INFORMATION

ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)
June 30,
2010

December 31,
2009ASSETSCurrent Assets:Cash and cash equivalents

$
4,380,344

$
24,885,546Accounts receivableTrade


4,652,043


2,562,779Accrued sales revenues


2,254,394


1,909,221Commodity price risk management asset


47,487


Inventory, prepaid expenses and other


11,614,720


7,647,870Total Current Assets


22,948,988


37,005,416Oil and gas properties (full cost method), at cost:Proved oil and gas properties


134,149,686


123,259,252Unproved oil and gas properties


20,141,970


12,068,156Wells in progress


10,376,683


2,691,107Facilities


405,334


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


(98,536,151
)

(95,782,438
)Net oil and gas properties


66,537,522


42,236,077Property and equipment, net of accumulated depreciation of $327,130 in 2010 and $284,535 in 2009


256,268


441,531Restricted investments


209,899


Deferred financing costs, net of amortization


330,891


Total Assets

$
90,283,568

$
79,683,024LIABILITIES AND STOCKHOLDERS' EQUITYCurrent Liabilities:Accounts payable and accrued liabilities

$
8,400,107

$
7,742,617Advances from joint interest owners


1,815,757


951,815Total Current Liabilities


10,215,864


8,694,432Noncurrent Liabilities:Long term debt


5,000,000


Asset retirement obligation


1,378,947


1,060,210Total Liabilities


16,594,811


9,754,642Commitments and ContingenciesNote 5Stockholders' Equity:Common stockno par value; unlimited authorizedIssued and outstanding: 119,604,910 shares in 2010 and 118,879,931 shares in 2009Contributed surplus


177,949,779


175,791,301Accumulated deficit


(104,261,022
)

(105,862,919
)Total Stockholders' Equity

$
73,688,757

$
69,928,382Total Liabilities and Stockholders' Equity

$
90,283,568

$
79,683,024


THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

2

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Table of Contents

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS        (Unaudited)

Three months ended
June 30,

For the six months ended
June 30,2010

2009

2010

2009Revenues:Gas production

$
198,854

$
129,329

$
432,095

$
411,803Oil production


5,921,777


1,860,808


11,409,501


2,356,066Unrealized gain on risk management activities


169,717





47,487


Interest income & other


5,974


22,893


16,158


36,520Total revenue


6,296,322


2,013,030


11,905,241


2,804,389Operating expenses:Oil and gas production


1,507,462


343,674


2,729,695


492,203Depletion, depreciation, amortization and accretion


1,529,951


532,454


2,850,556


887,794General and administrative


2,623,073


1,675,056


4,708,404


3,590,153Total operating expenses


5,660,486


2,551,184


10,288,655


4,970,150Interest Expense


14,689





14,689


Net income (loss) attributable to common shares

$
621,147

$
(538,154
)
$
1,601,897

$
(2,165,761
)Net income per common share:Basic

$
0.01

$
(0.01
)
$
0.01

$
(0.02
)Diluted

$
0.01

$
(0.01
)
$
0.01

$
(0.02
)Weighted average shares outstanding:Basic


119,341,821


100,235,806


119,137,589


97,696,724Diluted


120,299,724


100,235,806


120,603,115


97,696,724


THE
ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS

3

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KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS        (Unaudited)

For the six months ended
June 30,2010

2009Cash flows from operating activities:Net income (loss)

$
1,601,897

$
(2,165,761
)Reconciliation of net income (loss) to net cash provided by (used in) operating activities:Depletion, depreciation, amortization and accretion


2,850,556


887,794Change in fair value of commodity price risk management activities, net


(47,487
)

Stock based compensation


1,720,112


1,375,080Changes in current assets and liabilities:Accounts receivable-trade


(2,089,264
)

(798,812
)Accounts receivable-accrued sales revenue


(345,173
)

(1,120,452
)Prepaid expenses and other


(605,793
)

1,750,921Accounts payable and accrued liabilities


1,769,872


(622,402
)Net cash provided by (used in) operating activities


4,854,720


(693,632
)Cash flows from investing activities:Oil and gas properties


(25,055,809
)

(9,407,721
)Facilities, equipment & other


(509,472
)

8,000Prepaid tubular goods


(4,679,599
)

(993,413
)Restricted investment


(209,899
)

235,233Net cash (used in) investing activities


(30,454,779
)

(10,157,901
)Cash flows from financing activities:Borrowings under credit facility


5,000,000


Proceeds from the issuance of common shares


616,955


7,200,000Debt and share issuance costs


(522,098
)

(107,825
)Net cash provided by financing activities


5,094,857


7,092,175Net change in cash and cash equivalents


(20,505,202
)

(3,759,358
)Cash and cash equivalents at beginning of the period


24,885,546


7,581,265Cash and cash equivalents at end of the period

$
4,380,344

$
3,821,907Supplemental cash flow informationOil & gas property accrual included in Accounts payable and accrued liabilities

$
849,500

$
2,455,560Asset retirement obligation

$
331,050

$
139,290


THE
ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS

4

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Table of Contents

KODIAK OIL & GAS CORP.        NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1Organization

Description of Operations

Kodiak Oil & Gas Corp. (together with its subsidiary, "Kodiak," "we" or the "Company") is an independent energy company engaged
in the exploration, exploitation, development, acquisition and production of crude oil and natural gas entirely in the western United States. The common shares of the Company are listed for trading on
the NYSE Amex LLC and the Company's corporate headquarters are located in Denver, Colorado, USA.

The
Company was incorporated (continued) in the Yukon Territory, Canada 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. ("Kodiak USA"). All significant inter-company balances and transactions have been eliminated in consolidation. Substantially all of the Company's business is transacted in US dollars
and, accordingly, the financial statements are expressed in US dollars.

Liquidity and Capital Resources

We are maintaining our initial 2010 $60 million capital expenditure budget for drilling and completion costs. However, as a
result of the previously announced addition of leased acreage in strategic areas and the finalization of a pipeline infrastructure contract requiring capital to connect our existing wells, we have
increased our 2010 capital budget by $15 million, resulting in a total revised capital budget of $75 million.

This
revised capital expenditure budget remains subject to modification, both as to amount and allocation, and is subject to variation due to such factors as our drilling results,
availability and cost of oil field services and equipment and expected commodity prices, as well as available working capital.

We
expect to fund our revised capital budget primarily from working capital, anticipated cash flow from operations and borrowings under our reserve-based revolving credit facility. As of
June 30, 2010, our remaining capital budget of approximately $50.0 million is more than our working capital of approximately $12.7 million and the then undrawn balance on our
revolving credit facility of $15 million. We expect to fund the remaining portion of our revised capital budget by our cash flow from operations generated in the second half of 2010 in
combination with the potential increase of our borrowing base for our revolving credit facility. As compared to cash flow from operations in the first half of 2010, we anticipate that our operating
cash flows will increase as additional wells are drilled and placed on production. For the second quarter of 2010, our average production was 1,051 BOE per day. As a result of our drilling and
completion activities, we anticipate our average production to grow to over 2,500 BOE per day by the end of 2010, provided that we are able to complete the wells that we have scheduled for completion
in 2010. As of July 31, 2010, we have 5 gross wells (2.7 net) awaiting completion and project an additional 6 wells (3.7 net) will be completed prior to year end. Concurrently, we expect that
our borrowing base will increase with the addition of proved properties as a result of our drilling activities. However, we cannot give assurance that either our cash flow from operations or increases
in our borrowing base will be sufficient to fund our anticipated capital expenditures.

5

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

If
our existing and potential sources of liquidity are not sufficient to undertake our revised capital expenditures, we may alter our drilling program, pursue joint ventures with third
parties, sell interests in one or more of our properties or sell common shares or debt securities. 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 expenditures or restructure our operations, and we would be unable to implement our exploration and drilling program.

Use of Estimates in the Preparation of Financial Statements

The unaudited financial statements included herein were prepared from the records of the Company in accordance with generally accepted
accounting principles in the United States ("GAAP") applicable to interim financial statements and reflect all normal recurring adjustments which are, in the opinion of management, necessary to
provide a fair statement of the results of operations and financial position for the interim periods. Such financial statements conform to the presentation reflected in the Company's Annual Report on
Form 10-K filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2009. The current interim period reported herein should be read in
conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K for the year ended
December 31, 2009.

The
preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets
and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate
our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual
results may differ from these estimates under different assumptions or conditions, we believe that our 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.

Inventory, Prepaid Expenses and Other

Included in inventory, prepaid expenses and other are deposits made on orders of tubular goods and surface equipment required for the
Company's drilling program. As of June 30, 2010, this amount was approximately $10.7 million (consisting of $8.3 million of tubular goods and surface equipment that are
inventoried in third-party yards and $2.4 million of deposits for tubular goods that will be delivered later this year at such time that the tubular goods are required). In respect of the
$2.4 million tubular goods deposit, as of June 30, 2010, the Company estimates that an additional $4.8 million will be paid to complete the purchase and if the purchases are not
completed the deposits would be forfeited. At December 31, 2009, the Company had $7.3 million in tubular goods and surface equipment. The cost basis of the tubular goods is either
depreciated as a component of oil and gas properties once the

6

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

inventory
is used in drilling operations or billed to our partners through joint interest billings. The Company records tubular goods inventory at the lower of cost or market value. As of
June 30, 2010, and December 31, 2009, respectively, the Company's analysis of the difference between cost compared to market values for tubular goods not designated for specific wells
was not deemed material.

Restricted Investment

The restricted investment balance as of June 30, 2010, is comprised of: (a) $175,000 certificate of deposit to
collateralize a surety bond to provide for federal and state bonding requirements for plugging and abandonment liabilities; and (b) $34,899 certificate of deposit to collateralize the costs of
office improvements that will be released over the remaining term of the office lease.

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 has, on an ongoing basis, 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. To date, the Company has had minimal bad
debts.

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

Depletion
of 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 prepared (annually) 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 unproved properties are reviewed quarterly for impairment. When proved reserves are assigned or the unproved 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.

7

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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 are
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.

Costs
of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed quarterly to ascertain whether
impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and
becomes subject to depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based
on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure. For depletion and
depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Under
the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted
at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated
fair value, if lower of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net
revenues is computed by applying current prices of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be
incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. 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

8

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

basis
of the properties involved and the Company's Existing net operating losses ("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.

There
were no impairment charges recognized for the six month periods ended June 30, 2010 and 2009.

Wells in Progress

Wells in progress at June 30, 2010 and December 31, 2009 represent the costs associated with wells that have not reached
total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then
transferred to proved property when the wells are completed and the costs become subject to depletion and the ceiling test calculation in future periods.

Impairment of Long-lived Assets

The Company's unproved properties are evaluated quarterly for the possibility of impairment. In the six month period ended
June 30, 2010 and 2009, no unproved properties were impaired.

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.

Deferred Financing Costs

In May 2010, the Company recorded deferred financing costs of $344,000 related to the closing of its credit facility (see
Note 6). Deferred financing costs include origination, legal and engineering fees incurred in connection with the Company's credit facility, which are being amortized over the
four-year term of the credit facility. The Company recorded amortization expense of $29,806 (which includes the expensing of deferred financing costs from the Company's previous credit
facility) in the six month period ended June 30, 2010.

Commodity Derivative Instrument

Through its wholly-owned affiliate Kodiak USA, the Company has entered into commodity derivative contracts, as described below. The
Company has utilized "no premium" collars to reduce the effect of price changes on a portion of its future oil production. The objective of the Company's use of derivative financial instruments is to
achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the
downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time,

9

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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

The
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 contracts are
currently with two counterparties and the Company is a guarantor of Kodiak USA. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables
from separate derivative arrangements with each 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.

The
Company's commodity derivative contract as of June 30, 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


Subsequent
to June 30, 2010, the Company entered into an additional commodity derivative contract which is summarized below:

Contract Type

Counterparty

Basis

Quantity(Bbl/d)

Strike Price ($/Bbl)

TermCollar

Wells Fargo

NYMEX


400

$75.00/$89.20


Jan 1Dec 31, 2011


The
following table details the fair value of the derivatives recorded in the applicable condensed consolidated balance sheet, by category:

Fair Value atUnderlying Commodity

Location on Balance Sheet

June 30, 2010

December 31, 2009Crude oil derivative contract

Current asset

$
47,487

$



Unrealized
gains and losses resulting from derivatives are recorded at fair value on the condensed consolidated balance sheet and changes in fair value are recognized in the unrealized
gain (loss) on risk management activities line on the condensed consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in
the commodity price risk management activities line on the condensed consolidated statement of income. There were no realized gains or losses recorded for the six months ending June 30, 2010.

Fair Value of Financial Instruments

The Company's financial instruments, other than the derivative instrument discussed above, 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,

10

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KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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 June 30, 2010 and
December 31, 2009 were not significant.

Computation of Net Income (Loss) Per Share

Basic net income (loss) per share is computed by dividing net income (loss) attributable to the common stockholders by the weighted
average number of common shares outstanding during the reporting period. The shares of restricted common stock granted to certain officers and employees of the Company are included in the computation
of basic net income (loss) per share. Diluted net income per common share includes shares of restricted stock and the potential dilution that could occur upon exercise of the options to acquire common
stock computed using the treasury stock method, which assumes that the increase in the number of shares is reduced by the number of shares which could have been repurchased by the Company with the
proceeds from the exercise of the options (which were assumed to have been made at the average market price of the common shares during the reporting period).

The
table below sets forth the computations of basic and diluted net income (loss) per share for the three and six months ended June 30, 2010 and June 30, 2009.

For the three months Ended June 30,

For the six months Ended June 30,2010

2009

2010

2009Numerator:Basic net income

$
621,147

$
(538,154
)
$
1,601,897

$
(2,165,761
)Diluted net income (loss)

$
621,147

$
(538,154
)
$
1,601,897

$
(2,165,761
)Denominator:Basic weighted average common shares outstanding


119,341,821


100,235,806


119,137,589


97,696,724Effect of dilutive securitiesOptions to purchase common shares


6,104,917





3,104,917


Assumed treasury shares purchased


(5,147,015
)




(1,639,391
)

Diluted weighted average common shares outstanding


120,299,724


100,235,806


120,603,115


97,696,724Basic net income (loss) per share


0.01


(0.01
)

0.01


(0.02
)Diluted net income (loss) per share


0.01


(0.01
)

0.01


(0.02
)


For
the three and six month periods ended June 30, 2010, respectively, options to acquire 1,210,000 and 4,210,000 common shares were excluded from the diluted weighted average
shares outstanding because the exercise of these options would have been anti-dilutive.

11

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Asset Retirement Obligation

The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation
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 condensed
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 also included in the ceiling
test calculation. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of June 30, 2010 and December 31, 2009, the Company has
recorded a net asset of $877,917 and $603,526, respectively, and a related liability of $1,378,947 and $1,060,210, respectively. The information below reconciles the value of the asset retirement
obligation for the periods presented.

For the Six
Months Ended
June 30,
2010

For the Year Ended
December 31,
2009Balance beginning of period

$
1,060,210

$
787,180Liabilities incurred


266,455


251,671Liabilities settled


(66,561
)

(74,078
)Revisions


64,594


Accretion expense


54,249


95,437Balance end of period

$
1,378,947

$
1,060,210


Off Balance Sheet Arrangements

Other than standard operating leases and our drilling rig commitments as described in Note 5 below, the Company did not have any
other off balance sheet financing arrangements within the meaning of GAAP at June 30, 2010 and December 31, 2009.

Recently Adopted Accounting Pronouncements

In January 2010, the FASB issued Accounting Standards Update ("ASU") 2010-03,Extractive
ActivitiesOil and Gas (Topic 932),to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules.
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 applicable 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. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and gas reporting in ASC 932.10.S99-1 by
adding the Codification SEC Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU
2010-14 are effective for annual reporting

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

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.

In
January 2010, the FASB issued ASU 2010-06, "Improving Disclosures About Fair Value Measurements", which provides amendments to fair value disclosures. ASU
2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out
of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3
disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Neither the current requirements nor the amendments effective in 2011 will have a
material impact on the Company's financial position or results of operations.

Note 3Wells in Progress

The following table reflects the net changes in capitalized additions to wells in progress during the six months ended June 30, 2010 and the year ended December 31, 2009,
and includes amounts that were capitalized and reclassified to producing wells in the same periods.

For the Six
Months Ended
June 30,
2010

For the Year Ended
December 31,
2009Beginning balance

$
2,691,107

$
728,093Additions to capital wells in progress costs pending the determination of proved reserves


11,439,388


16,127,748Reclassifications to wells, facilities, and equipment based on the determination of proved reserves to full cost pool


(3,753,812
)

(14,164,734
)Ending balance

$
10,376,683

$
2,691,107


As
of June 30, 2010, wells in progress included seven gross (4.0 net) Kodiak-operated, three gross (0.2 net) non-operated wells in the Williston Basin and two gross
(0.5 net) non-operated wells in the Green River Basin. Two of the Williston Basin Kodiak-operated wells classified as wells-in-progress as of June 30, 2010
were completed in July 2010, and the remaining are anticipated to be completed in the third and fourth quarters of 2010. The Green River Basin wells in progress were drilled in 2008 and 2009 and
completion work is anticipated to continue in 2010.

Note 4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 2007 Plan authorized the Company 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 to any employee, consultant, independent
contractor, director or officer of the Company. On June 3, 2010, the shareholders of the Company approved Amendment No. 1 to the Company's 2007 Plan to increase the maximum number of
shares of the Company's common stock, no par value, available for grant under the 2007 Plan from 8,000,000 shares to 16,600,000 shares through December 31, 2010. Each subsequent year, the
maximum number

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Stock-based Compensation Plan (Continued)

of
shares of common stock available for issuance under the 2007 Plan, as amended, will be equal to 14% of the Company's then outstanding shares of common stock.

The
Company granted stock options to acquire 2,460,000 common shares at a weighted average exercise price of $3.09 per share and 1,150,000 stock options at a weighted average exercise
price of $1.18 per share during the six month periods ended June 30, 2010 and June 30, 2009, respectively.

Compensation
expense charged against income for all stock-based awards during the six months ended June 30, 2010 and 2009 on a pre-tax basis was approximately
$1.7 million and $1.4 million, respectively, which is included in general and administrative expense in the condensed consolidated statements of operations.

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

For the Six
Months Ended
June 30,
2010

For the Year Ended
December 31,
2009Risk free rates


1.18 - 3.02
%

1.24 - 1.34
%Dividend yield


0
%

0
%Expected volatility


99.20 - 102.11
%

107.01 - 108.93
%Weighted average expected stock option life


4.38 years


2.97 yearsThe weighted average fair value at the date of grant for stock options granted is as follows:Weighted average fair value per share

$
2.14

$
0.77Total options granted


2,460,000


1,150,000Total weighted average fair value of options granted

$
5,254,487

$
865,433


14

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Stock-based Compensation Plan (Continued)

A
summary of the stock options outstanding as of June 30, 2010 is as follows:

Number
of Options

Weighted
Average
Exercise
PriceBalance outstanding at January 1, 2009


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

$
2.36Granted


2,460,000


3.09Canceled


(105,104
)

2.25Expired





Exercised


(624,979
)

0.99Balance outstanding at June 30, 2010


7,314,917

$
2.73Options exercisable at June 30, 2010


4,227,883

$
2.73


At
June 30, 2010, stock options outstanding were as follows:

Exercise Price

Number
of Shares

Weighted Average
Remaining Contractual
Life (Years)$0.36 - $1.00


567,000


8.50$1.01 - $2.00


1,355,917


3.20$2.01 - $3.00


1,135,000


8.71$3.01 - $4.00


3,752,000


4.34$4.01 - $5.00


190,000


0.99$5.01 - $6.26


315,000


6.907,314,917


5.15


The
aggregate intrinsic value of both outstanding and vested options as of June 30, 2010 was $3,367,613 based on the Company's June 30, 2010 closing common stock price of
$3.19 per share. The total grant date fair value of the shares vested during the six months ended June 30, 2010 was $1,579,817. As of June 30, 2010, there was $4,272,042 of total
unrecognized compensation cost related to unamortized options. That cost is expected to be recognized over a period of approximately three years.

15

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Stock-based Compensation Plan (Continued)

As of June 30, 2010, there were 15,000 unvested shares of restricted stock with a weighted-average grant date fair value of $3.69 per share. Total unrecognized compensation cost
of $29,333 related to non-vested restricted stock is expected to be recognized over a twelve month period. The Company recognizes compensation cost over the requisite service period for
the entire award. 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.

Note 5Commitments and Contingencies

The Company leases office facilities in Denver, Colorado and Dickinson, North Dakota under operating lease agreements that expire on June 30, 2012 and December 31, 2010,
respectively. Rent expense for the Company's Denver, Colorado office was $129,669 and $104,409 for the six month periods ended June 30, 2010 and 2009, respectively.

The
following table shows the remaining annual rentals per year for the life of the Denver office space lease:

Years ending on December 31,2010


146,4512011


303,1712012


154,172Total

$
603,794


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 to September 15, 2010.

The
contract can be extended by mutual consent of Kodiak and the drilling contractor at its termination. The estimated termination fee for this first rig is $1.8 million as of June 30,
2010. The second rig was placed into operation in March 2010 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior to
March 10, 2012. This contract can also be extended by mutual consent. The estimated termination fee for the second rig is $4.8 million as of June 30, 2010. The Company is
currently utilizing both rigs for drilling in the Williston Basin and expects to continue utilization through their respective terms.

During
the second quarter of 2010, the Company entered into a contract for the use of an additional drilling rig. We originally anticipated placing this third rig into operation in the
fourth quarter of 2010; however, we recently entered into an agreement with a third party operator, pursuant to which the operator will utilize the rig through the first six months of the underlying
drilling rig contract. The rig contract entails a one-year drilling commitment or specific termination fees if the contract is terminated prior to delivery of the rig. The contract may
also be extended by mutual consent. The estimated termination fee for this third rig is $3.8 million as of June 30, 2010. Having the rig become available later in 2011 provides the
Company alternatives that defer the decisions as to the timing of adding a third rig.

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Commitments and Contingencies (Continued)

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 6Credit Facility

On May 24, 2010, the Company, through its wholly-owned subsidiary, Kodiak USA, entered into a $200 million, four-year, revolving, senior secured credit
agreement with Wells Fargo Bank, N.A. (the "Lender"). The outstanding principal balance of the revolving loan, together with all unpaid fees and expenses relating thereto, shall be due and payable no
later than May 24, 2014. As of June 30, 2010, the Company had borrowed $5.0 million under the credit agreement. Subsequent to June 30, 2010, the Company borrowed an
additional $2.5 million under the credit agreement.

Concurrent
with the credit agreement, the Company entered into a guarantee pursuant to which the Company guarantees to the Lender all of the obligations of Kodiak USA under the credit
agreement and pledges a security interest in 100% of its equity interests in Kodiak USA as collateral support for its obligations under the guaranty and the obligations of Kodiak USA under the credit
agreement. Additionally, Kodiak USA granted a security interest in substantially all of its assets, including mortgages on at least 80% of its interests in oil and gas properties on a discounted
basis. Availability under the credit agreement is subject at all times to the then applicable borrowing base, which is recalculated with scheduled redeterminations at December 31 and
June 30 of each year. The Company can request two additional redeterminations per year, thereby allowing for the ability to adjust the borrowing base up to four times in a calendar year. The
borrowing base was $20.0 million as of June 30, 2010.

The
credit agreement also makes available to the Company standby letters of credit in an amount equal to the lesser of the then applicable borrowing base and $5,000,000 and reduces
availability for loans under the credit agreement on a dollar for dollar basis. The Company had no outstanding standby letters of credit under the credit agreement as of June 30, 2010.

Interest
on the revolving loans is payable at one of the following two variable rates: the Alternate Base Rate for ABR Loans or the Adjusted LIBO Rate for Eurodollar loans, as selected
by the Company, plus an additional percentage that can vary on a daily basis and is based on the daily unused portion of the facility. This additional percentage is referred to as the "Applicable
Margin" and varies depending on the type of loan. The grid below shows the Applicable Margin options depending on the applicable Borrowing Base Utilization Percentage.

Borrowing Base Utilization Grid

Borrowing Base Utilization Percentage


<25.0
%
325.0% <50.0%

350.0% <75.0%

375.0% <90.0%

390.0%Eurodollar Loans


2.25
%
2.50%

2.75%

3.00%

3.25%ABR Loans


1.25
%
1.50%

1.75%

2.00%

2.25%Commitment Fee Rate


0.50
%
0.50%

0.50%

0.50%

0.50%


The credit agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including
but not limited to: (a) covenants to comply with a current ratio of consolidated current assets to consolidated current liabilities not less than 1.0:1.0 and a

17

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6Credit Facility (Continued)

ratio
of total debt to EBITDAX (as defined in the credit agreement) not greater than 3.75:1.0; (b) limitations on liens and incurrence of debt covenants; (c) limitations on dividends,
distributions,
redemptions and restricted payments covenants; (d) limitations on investments, loans and advances covenants; and (e) limitations on the sale of property, mergers, consolidations and
other similar transactions covenants. As of June 30, 2010, the Company was in compliance with all covenants under the credit agreement.

Note 7Fair Value Measurements

ASC Topic 820 establishes a hierarchy for inputs used in measuring fair value that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that
the most observable inputs be used when available. Observable inputs are inputs that market participants would use in pricing the asset or liability developed based on market data obtained from
sources independent of the Company. Unobservable inputs are inputs that reflect the Company's assumptions of what market participants would use in pricing the asset or liability developed based on the
best information available in the circumstances. The hierarchy is broken down into three levels based on the reliability of the inputs as follows:



The
financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of
a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The
following table presents the Company's financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2010 by level within the fair
value hierarchy:

Fair Value Measurements UsingLevel 1

Level 2

Level 3

TotalAssetsCommodity price risk management asset





47,487





47,487Liabilities:Commodity price risk management liability














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

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Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7Fair Value Measurements (Continued)

to
meet its potential repayment obligations associated with the derivative transactions. At June 30, 2010, derivative instruments utilized by the Company consist of a "no cost" collar. The
crude oil derivative markets are highly active. Although the Company's derivative instruments are valued using public
indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

Other
financial instruments not measured at fair value on a recurring basis include cash and cash equivalents, accounts receivable, note receivable, accounts payable, and accrued
liabilities. The financial statement carrying amounts of these items approximate their fair values due to their short-term nature.

Note 8Differences Between Canadian and United States Accounting Principles

These financial statements have been prepared in accordance with GAAP, 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 ("Canadian GAAP"). Management does not believe its 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 would have a material effect
on the accompanying financial statements.

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Table of Contents

ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Forward-Looking Statements

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



20

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Table of Contents



Finally,
our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in our filings with the SEC and in Part II,
Item 1A of this Quarterly Report. For additional information regarding risks and uncertainties, please read our filings with the SEC under the Exchange Act and the Securities Act, including our
Annual Report on Form 10-K for the fiscal year ended December 31, 2009. All forward-looking statements attributable to us or persons acting on our behalf are expressly
qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this Quarterly Report. Other than as required under securities laws, we do not assume a duty to update these
forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

Overview

Kodiak 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

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Table of Contents

and
exploratory drilling opportunities on high potential conventional and non-conventional oil and natural gas prospects that we have the opportunity to explore, drill and develop.

Liquidity and Capital Resources

Our original 2010 capital expenditure budget of approximately $60 million was substantially allocated to drilling and completion
activities and we are maintaining those capital expenditures. We have revised our original 2010 capital expenditure budget to a total of $75 million primarily due to the addition of leased
acreage in strategic areas and the finalization of a pipeline infrastructure contract requiring capital to connect our wells.

In
summary, the increase in our capital budget was primarily due to the following factors:



This
revised capital expenditure budget remains subject to modification, both as to amount and allocation, and is subject to variation due to such factors as our drilling results,
availability and cost of oil field services and equipment and expected commodity prices, as well as available working capital.

In
total, we have the potential for participation in as many as five gross rigs by mid-year 2011. In the second quarter of 2010, we contracted for delivery of a drilling rig
that we intend to operate in addition to our two current rigs. We have recently reached an agreement with a third party operator for their continued usage of this rig through the first six months of
the contract. As a result, this rig should be available to us during the second quarter of 2011. The third contracted rig does not have a skid package, so it is more suitable to single well drilling
pads, providing us flexibility in our rig inventory. In addition, our partner in an area of mutual interest covering a portion of our acreage has indicated they will be mobilizing one rig in the
fourth quarter of 2010 followed by a second in early 2011. Our interest in the wells drilled by this partner would vary, but within the area of mutual interest we would have a 50% working interest
ownership. The largest increase in the drilling activity would occur in 2011.

We
expect to fund our revised capital budget primarily from working capital, anticipated cash flow from operations and borrowings under our reserve-based revolving credit facility. As of
June 30, 2010, our remaining capital budget of approximately $50.0 million is more than our working capital of approximately $12.7 million and the then undrawn balance on our
revolving credit facility of $15 million. We expect to fund the remaining portion of our revised capital budget by our cash flow from operations generated in the second half of 2010 in
combination with the potential increase of our

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Table of Contents

borrowing
base for our revolving credit facility. As compared to cash flow from operations in the first half of 2010, we anticipate that our operating cash flows will increase as additional wells are
drilled and placed on production. For the second quarter of 2010, our average production was 1,051 BOE per day. As a result of our drilling and completion activities, we anticipate our average
production to grow to over 2,500 BOE per day by the end of 2010, provided that we are able to complete the wells that we have scheduled for completion in 2010. As of July 31, 2010, we have 5
gross wells (2.7 net) awaiting completion and project an additional 6 wells (3.7 net) will be completed prior to year end. Concurrently, we expect that our borrowing base will increase with the
addition of proved properties as a result of our drilling activities. However, we cannot give assurance that either our cash flow from operations or increases in our borrowing base will be sufficient
to fund our anticipated capital expenditures.

If
our existing and potential sources of liquidity through increased operating cash flows or our credit facility are not sufficient to undertake our revised capital expenditures, we may
alter our drilling program, pursue joint ventures with third parties, sell interests in one or more of our properties or sell common shares or debt securities. There can be no assurance that any such
transactions can be completed or that such transactions will satisfy our 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 expenditures or restructure our operations, and we would be unable to implement our exploration and drilling program.

During
the first six months of 2010, we incurred capital expenditures of approximately $26.7 million. The table below sets forth our capital expenditures for the six months ended
June 30, 2010,

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Table of Contents

and
our revised budgeted capital expenditures for 2010 for our principal properties. Net capital expenditures include both cash expenditures and accrued expenditures and are net of proceeds from
divestitures.

Project Location

2010 Net Capital
Expenditures(1)
($000)

Revised 2010
Budgeted Net
Capital Expenditures
($000)Williston BasinMission Canyon/Red River wells and related infrastructure


1,100


1,300Bakken wells and related infrastructure


15,100


60,000Acreage/Seismic


10,100


13,350Total Williston Basin

$
26,300


74,650Wyoming

$
350

$
350Total All Areas

$
26,650

$
75,000


(1)Net
Capital Expenditures include accruals and are net of proceeds from divestitures.


During
the first six months of 2010, we drilled or participated in 10 gross wells (3.9 net) and completed 5 gross wells (2.2 net). In total, we anticipate drilling or participating in 20
gross wells (9.3 net) and completing 17 gross wells (9.2 net) during 2010. All of these wells are in our Williston Basin operating area.

The
following table sets forth our capital resources and liquidity as of and for the three and six month periods ended June 30, 2010 and 2009:

For the three months
ended June 30,

For the six months
ended June 30,2010

2009

2010

2009Capital Resources and LiquidityCash and cash equivalents at end of the period

$
4,380,344

$
3,821,907

$
4,380,344

$
3,821,907Net cash provided by (used in) operating activities


7,261,380


1,779,759


4,854,720


(693,632
)Net cash used in investing activities


(18,430,239
)

(7,057,450
)

(30,454,779
)

(10,157,901
)Net cash provided by financing activities


4,982,177


7,092,175


5,094,857


7,092,175Net cash flow


(6,186,682
)

1,814,484


(20,505,202
)

(3,759,358
)


Kodiak
ended the first half of 2010 with total working capital of approximately $12.7 million, which included cash and cash equivalents of approximately $4.4 million, as
compared to working capital of approximately $28.3 million at year-end 2009, which included cash and cash equivalents of approximately $24.9 million. An important component
of our working capital is our inventory, prepaid expenses and other current assets. As operator of most of our current activity in the Williston Basin, we must place orders and take delivery of
tubular goods in advance of actual drilling in order to assure availability of the tubular goods. As wells are drilled, these tubular goods become part of our cost of wells, whereby our working
interest share is already paid while the portion related to other working interest partners is recovered through our joint interest billings. As of June 30, 2010, we had prepaid
$10.7 million towards the cost of tubular goods, compared to $7.3 million at December 31, 2009.

Our
working capital alone is not sufficient to fund our remaining revised 2010 capital expenditure budget of approximately $50 million. We anticipate that cash flow from
operations, in addition to increased borrowing under our reserve-based revolving credit facility, will be used to fund such

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Table of Contents

remaining
budgeted capital expenditures. We expect our operating cash flows and borrowing base to continue to increase as additional wells are drilled and placed on production. However, the increases
in both of these sources are subject to our ability to complete the wells that we have scheduled for completion in 2010. As of July 31, 2010, we have 5 gross wells (2.7 net) awaiting completion
and project an additional 6 wells (3.7 net) to be completed prior to year end. If we can achieve production rates that we have seen from our existing wells, we anticipate a strong increase in our
production base. Concurrently, we expect that our borrowing base will increase with the addition of proved properties as a result of our drilling activities. However, we cannot give assurance that
either our cash flow from operations or increases in our borrowing base will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through
increased operating cash flows or our credit facility are not sufficient to undertake our revised capital expenditures, we may alter our drilling program, pursue joint ventures with third parties,
sell interests in one or more of our properties or sell common shares or debt securities. There can be no assurance that any such transactions can be completed or that such transactions will satisfy
our 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 expenditures or restructure our operations, and we would be unable to implement our exploration and drilling program.

Our
results of operations and financial condition are significantly affected by the success of our exploration and land leasing activity, the resulting production and reserves, oil and
natural gas commodity prices and the costs related to operating our properties. In the six months ended June 30, 2010, our oil and natural gas revenue increased by approximately 328% from
$2.8 million for the six months ended June 30, 2009 to $11.8 million for the six months ended June 30, 2010. This increase is largely the result of the increase in our
crude oil production in 2010 compared to 2009, together with improved prices realized for our oil and natural gas production. Total costs and expenses increased to $10.3 million for the six
months ended June 30, 2010 from $5.0 million for same period of 2009. This increase is primarily due to our increased lease operating expense resulting from adding ten wells to
production from June 30, 2009 to June 30, 2010, the related severance taxes paid on production from the wells added and the increase in depletion due to the same wells added to our
production base.

In
May 2010, we (through our wholly-owned subsidiary) entered into a credit agreement with a large commercial bank. The credit facility has a $20 million borrowing base as of
June 30, 2010, which is subject to semi-annual redetermination. We are obligated to make periodic interest or other debt service payments related to the funds we borrow under the
credit facility and we are subject to various restrictive covenants. The amount of our borrowing base is dependent on a number of variables, including our proved reserves, and assumptions regarding
the price at which oil and natural gas can be sold. We currently have $7.5 million outstanding under our credit facility.

Properties

Williston Basin

Our primary geologic targets in the Williston Basin are the Bakken and Three Fork Formations. The Williston Basin also produces from
many other formations including, but not limited to, the Mission Canyon, Nisku and Red River. We are currently operating a two-rig program in the Williston Basin and currently anticipate
continued operation throughout 2010 with these rigs. As previously mentioned, these two rigs are under two-year contracts that expire in the fourth quarter of 2010 and the first quarter of
2012, respectively. In the second quarter of 2010, we contracted for a third drilling rig from the same drilling contractor as the aforementioned rig contracts. As opposed to the first two rigs, the
third rig does not have a skid package, which will provide us the flexibility to utilize the rig on single well pads while utilizing the other two rigs to drill multiple wells from one drilling pad.
Recently, we entered into an agreement with a third party operator, pursuant to which the operator will utilize the rig through the first six months of the underlying drilling rig contract. By having
the rig become

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available
for delivery in 2011, we are provided with alternatives that defer the decisions as to the timing of adding a third rig. In addition to our operated rigs, we have been informed by our joint
venture partner on the Fort Berthold Indian Reservation that they will be mobilizing a drilling rig later this year on the lands they operate with the expectation to add a second rig during the first
part of 2011. While we do not know the drilling program for these rigs, we anticipate having a working interest of up to 50% in several of the wells to be potentially drilled by these two rigs.

In
the six months ended June 30, 2010, the Company's capital expenditures in the Williston Basin totaled $26.3 million, including $16.2 million for drilling and
completion activities and $10.1 for acreage
leasing. For the entire year of 2010, our revised capital expenditure budget for the Williston Basin includes $61.3 million for drilling and completion and related infrastructure and
$13.3 million for acreage leasing.

Bakken/Three Forks Development: Dunn County, N.D. (55,775 gross and 34,635 net acres)

In late July 2010, the Company completed the Moccasin Creek (MC) #13-34-28-2H (Kodiak-operated 59%
working interest (WI) / 48% net revenue interest (NRI)) well. The well was completed in 15 stages through a 6,200-foot horizontal wellbore. The well has been flow tested for three days and
has not stabilized sufficiently to report a 24-hour initial production rate. Over the last 12 hours prior to the filing of this quarterly report, the well flow-tested at
rates between 70 to 80 barrels of oil per hour and 900 to 1,200 thousand cubic feet of natural gas (Mcf) per day through a 24/64th inch choke with 2,850 psi flowing surface pressure.
During the 12-hour period, the well had cumulative oil production of 871 barrels of oil and 541 Mcf. Presently, the well is flowing back approximately 60% frac fluid and 40% oil. Kodiak
continues to flow test the well and will turn in to permanent production facilities when testing is completed.

As
of July 31, 2010, the Company has three wells in Dunn County awaiting completion. The MC # 13-34-28-1H is a
9,769-foot horizontal lateral directly offsetting the MC#13-34-28-2H well discussed above and is currently being completed. Also awaiting completion is
the Two Shields Butte (TSB) #14-21-4H well, which is a 4,500-foot horizontal lateral, and the TSB 14-21-33-16H3 well, a 9,300
foot horizontal lateral drilled in the Three Forks Formation. These wells are the first two wells drilled from the TSB four-well pad.

Kodiak
is currently drilling ahead on the TSB # 14-21-33-15H, a projected 9,000-foot lateral and the TSB
#14-21-16-2H, a projected 9,000 foot lateral, will follow. It is expected that these four wells on the shared pad will be completed during the fourth quarter of
2010.

The
Company has a 7.15% working interest in two wells drilled from one pad by another operator. One of the wells was drilled and has been completed in the Middle Bakken and had a
reported curtailed initial production rate of 1,385 BOE/d. The second well was drilled in Three Forks Formation and is currently awaiting completion.

McKenzie County, N.D. (13,430 gross and 9,565 net acres)

In the Grizzly project area, located in the Mondak Field of the southeastern Elm Coulee trend, the Grizzly
#13-6-H-R (Kodiak operated68% working interest / 56% net revenue interest) was re-entered during June 2010 and a 3,700-foot lateral was
drilled horizontally in the Middle Bakken Formation and is currently undergoing completion operations.

We
are currently drilling the Grizzly Federal #1-27H-R well, a proposed 9,600-foot horizontal lateral test of the Middle Bakken Formation. The well is a twin to
the Grizzly Federal #1-27 well, which was drilled and completed in 2007 using single-stage fracture stimulation procedures.

After
drilling is completed on the Grizzly Federal #1-27H-R well, we intend to relocate the drilling rig to our Koala acreage block. The first well expected to be drilled
will be the Koala

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#9-5-6-5H
well, followed by the Koala #9-5-6-5H3 well (both Kodiak operated74.7% working interest / 61.3% net
revenue interest).

The
following summary provides a tabular presentation of data pertinent to Kodiak's Middle Bakken and Three Forks drilling and completion activities during 2010 (gas is converted on a 6
Mcf to 1 barrel of oil basis):

Kodiak Oil & Gas Corp. N.D. (Bakken) Drilling and Completion ActivitiesLonger Laterals (8,000' to 10,000')Dunn County, N.D.ProductionIP
24-Hour
Test
BOE/D



Gas / Oil
Ratio
(GOR)
RangeWell

WI / NRI
(%)

Completion
Date

30 Day
Cum
BOE

60 Day
Cum
BOE

90 Day
Cum
BOE

1st 90 Day
Average
BOE/d

StatusMC #13-34-28-1H


59 /48


Q310



















CompletingTSB #14-21-33-16H3


50 /41


Q410



















Waiting completionTSB #14-21-33-15H


50 /41


Q410



















DrillingTSB #14-21-16-2H


50 /41


Q410



















Spud in 3Q 2010Shorter Laterals (4,000' to 7,000')Dunn County, N.D.MC #16-3-11H


60 /49


2/12/2010


1,419


23,937


41,610


55,846


621


800

Flowing wellMC #16-3H


60 /49


3/2/2010


1,495


20,119


32,224


43,003


478


800

Flowing wellMC #13-34-3H


60 /49


6/7/2010


1,517


19,982











650

Flowing wellMC #13-34-28-2H


59 /48


8/2/2010



















Flowing wellTSB #14-21-4H


50 /41


Q410



















Waiting completionMcKensie County, N.D.Grizzly 13-6-R


68 / 56


Q310



















Waiting completionGrizzly 1-27H-R


74 / 60






















DrillingKoala 9-5-6-5H


75 / 61






















Spud in 3Q 2010


Red River Formation: Sheridan County, Mont.

The Harshbarger #13-20-29 (Kodiak operated43% working interest / 34% net revenue interest) was
recently completed and production testing is continuing at this time. We are currently utilizing workover rigs on our Bakken acreage and once that work is completed, we will mobilize back on this well
and finish our completion work.

Midstream Activities: Oil, Gas and Water Disposal Pipelines and Water Intake Facilities

In late June, Kodiak reached a definitive agreement with a third-party pipeline operator that allows for the gathering and sales of
crude oil and natural gas and gathering and disposal of water through pipelines over certain of the Company's Dunn County gross acreage position. The Company's joint venture partner in this area that
operates a portion of Kodiak's leasehold had previously reached an agreement with the same pipeline operator. Combined, these agreements allow all of the wells completed by either company within the
area of mutual interest to produce into the same gathering and pipeline system.

The
gathering system will run through the northern part of Kodiak's Dunn County leasehold and connect four of the Company's currently producing wells. Furthermore, the pipeline will
accommodate
the Company's remaining 2010 drilling with one of the Company's drilling rigs, including the TSB four-well pad currently being drilled. Moving oil and gas quantities through the pipeline
system eliminates trucking costs and associated surface disturbance and mitigates weather-related production interruptions. Additionally, Kodiak can capture revenue generated from the sales of its
associated natural gas and natural gas liquids that are currently flared. The pipeline agreement also includes water gathering and disposal which can further reduce lease operating expense while
minimizing surface disturbance by eliminating the trucking of water.

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Kodiak
also recently entered into an exclusive definitive agreement with the Three Affiliated Tribes and the state of North Dakota for the construction of a water intake facility that
accesses water from the nearby Missouri River. The water will be used for operational needs, including fracture stimulations. The new water intake facility is expected to eliminate significant
trucking traffic and costs, as well as reduce the need to draw water from underground aquifers. Kodiak expects to have the facility operational by the end of the fourth quarter of 2010, subject to
federal regulatory approvals.

Green River Basin (47,867 gross and 15,056 net acres)

We have been notified by the operator of the Vermillion Basin prospect that they intend to re-enter a well that was
vertically drilled in 2008 to the top of the Baxter Shale and horizontally drill a lateral to evaluate the potential of the Baxter Shale interval. We have not allocated significant capital to this
project, as we expect to be carried for these expenditures under our current contract with the operator.

Production, Average Sales Prices and Production Costs

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. Market prices reflect worldwide concerns regarding economic conditions and demand for petroleum products,
amid a host of uncertainties caused by political instability, fluctuations in the U.S. dollar and crude oil refining constraint. We receive lower prices for our oil and gas than what is posted on the
New York Mercantile Exchange ("NYMEX"). The price differentials received for our products vary from month to month, and we have limited commodity price hedges in place.

The
Company's oil and gas sales volumes are directly related to the results of its exploratory and acquisition activities. Production volumes may vary monthly as various wells are
completed or maintained in an effort to provide optimal production. Sales volumes, prices received and production costs are summarized in the following table for the three and six month periods ended
June 30, 2010 and June 30, 2009.

For the three
months ended

For the six
months endedJune 30,
2010

June 30,
2009

June 30,
2010

June 30,
2009Sales Volume (Bakken only):Gas (Mcf)


2,011


1,856


3,884


3,364Oil (Bbls)


80,306


25,287


152,120


28,866Production volumes (BOE)


80,641


25,596


152,767


29,427Sales Volume (Total):Gas (Mcf)


50,805


58,878


93,882


158,572Oil (Bbls)


87,203


35,314


164,409


51,800Production volumes (BOE)


95,671


45,127


180,056


78,229Price:Gas ($/Mcf)

$
3.91

$
2.20

$
4.60

$
2.60Oil ($/Bbls)

$
67.91

$
52.69

$
69.40

$
45.48Production costs ($/BOE):Lease operating expenses

$
7.53

$
2.37

$
7.06

$
3.12Production and property taxes

$
7.63

$
4.88

$
7.72

$
2.48Gathering, transportation, marketing

$
0.60

$
0.36

$
0.38

$
0.69


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Results of Operations

For the Three Months Ended June 30, 2010 compared to the Three Months Ended June 30, 2009

The Company reported net income for the three months ended June 30, 2010 of approximately $621,000 compared to a net loss of
$538,000 for the same period in 2009. The improvement from a net loss to net income is attributable to the new production from our Bakken wells, which includes sales from one recently completed Bakken
well which came on to production in the second quarter of 2010. Our volumes on a BOE basis increased 112% from 45,127 BOE in the second quarter of 2009 to 95,671 BOE during the second quarter of 2010.
In addition, we realized increased prices for both oil and natural gas during the three month period ended June 30, 2010 versus the three month period ended June 30, 2009. Oil price
realizations increased by 29% to $67.91 per barrel for the three month period ended June 30, 2010, compared to $52.69 per barrel for the same period in 2009. Total natural gas price
realizations increased 78% to $3.91 per Mcf for the three month
period ended June 30, 2010, compared to $2.20 per Mcf for the same period in 2009. Our increased oil production and, to a lesser extent, the increased pricing received for our products, for the
period resulted in an increase in oil and gas revenue of $4.1 million, from approximately $2.0 million for the three-month period ended June 30, 2009 to $6.1 million for
the same period in 2010, a 207% increase.

The
following table sets forth of the Company's financial results, capital resources and liquidity as of and for the three months ended June 30, 2010 as compared to the three
months ended June 30, 2009.

For the three months endedJune 30, 2010

June 30, 2009Financial ResultsTotal revenue

$
6,296,322

$
2,013,030Total costs and expenses

$
5,660,486

$
2,551,184Net income (loss)

$
621,147

$
(538,154
)Basic net income (loss) per common share

$
0.01

$
(0.01
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
4,380,344

$
3,821,907Net cash provided by operating activities

$
7,261,380

$
1,779,759Cash used in investing activities in oil and gas properties, net of divestitures

$
(17,609,109
)
$
(5,590,294
)


Oil and Gas Revenue and Production

During the three month period ended June 30, 2010, as compared to the same period in 2009, crude oil production volumes
increased 147% due to new production from completion operations on our Dunn County, North Dakota operating area. Natural gas production volumes decreased 14% due to our decision to limit production on
our Wyoming wells and declines in other gas well production. Oil and natural gas revenues increased by $4.1 million, or 207%, compared to the first quarter of 2009, primarily due to our
increased volumes attributable to our recent well completions and, to a lesser extent, increased realized pricing for oil and natural gas in 2010 versus 2009. The increase in oil and gas revenue was
85% attributable to the increase in production volumes and 15% attributable to the increase in realized commodity prices.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of approximately $1.5 million during the three month
period ended June 30, 2010, as compared to approximately $344,000 during the same period in 2009. The increase is due to our increased lease operating expenses

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on
the ten new wells in production as of June 30, 2010 that were not in production in 2009 and the related severance taxes paid related to the revenue received on the new wells production. A
significant portion of the operating expense is related to the disposal of water in the early months of a well's production. Since a majority of the water is related to completion operations and is
largely diminished after two to three months, the well's operating expenses decline over its early production period. Overall, we have continued to bring new wells online and, as a result of the water
disposal costs, our total operating expenses reflect the added cost of water disposal.

Depletion, Depreciation and Amortization

Depreciation, depletion, amortization and abandonment liability accretion, or DD&A, was approximately $1.5 million for the three
month period ended June 30, 2010, compared to $532 thousand for the same period in 2009. DD&A expense increased during the quarter due to increased production for the new wells placed in
service from the second quarter of 2009 through the second quarter of 2010.

Ceiling Test Impairment

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. For the three months ended June 30, 2010 and
June 30, 2009, respectively, no impairment charges were recorded.

General and Administrative Expense

The Company's general and administrative costs were approximately $2.6 million for the three months ended June 30, 2010
compared to approximately $1.7 million for the same period in 2009. This 57% increase for the period is primarily due to adding additional employees in 2010 as the Company has increased its
operational activities in the Williston Basin. We currently have 27 employees as compared to 16 at the end of 2009. Further, as we have grown our production base in the Williston Basin, we have
established a regional office in Dickinson, North Dakota, that is staffed by permanent field employees that directly oversee our ongoing activities.

For the Six Months Ended June 30, 2010 compared to the Six Months Ended June 30, 2009

The Company reported net income for the six months ended June 30, 2010 of approximately $1.6 million compared to a net
loss of $2.2 million for the same period in 2009. The improvement from a net loss to net income is attributable to the new production from our Dunn Country, North Dakota Bakken wells, where our
first wells began producing in the second quarter of 2009, and includes sales from three Bakken wells which came on to production during 2010. For the six months ending June 30, 2010, our
volumes on a BOE basis increased 130% from 78,229 BOE in the first half of 2009 to 180,056 BOE during the first half of 2010. In addition, we realized increased prices for both oil and natural gas
during the six month period ended June 30, 2010 versus the six month period ended June 30, 2009. Oil price realizations increased by 53% to $69.40 per barrel for the six month period
ended June 30, 2010, compared to $45.48 per barrel for the same period in 2009. Total natural gas price realizations increased 77% to $4.60 per Mcf for the six month period ended
June 30, 2010, compared to $2.60 per Mcf for the same period in 2009. Our increased oil production and, to a lesser extent, the increased pricing received for our products for the period
resulted in an increase in
oil and gas revenue of $9.0 million, from approximately $2.8 million to $11.8 million, a 328% increase in revenue for the six month period ended June 30, 2010 compared to
the same period in 2009.

30

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Table of Contents

The following table sets forth the Company's financial results, capital resources and liquidity as of the six months ended June 30, 2010 as compared to the
six months ended June 30, 2009.

For the six months endedJune 30, 2010

June 30, 2009Financial ResultsTotal revenue

$
11,905,241

$
2,804,389Total costs and expenses

$
10,288,655


4,970,150Net income (loss)

$
1,601,897

$
(2,165,761
)Basic and diluted net income (loss) per common share

$
0.01

$
(0.02
)Capital Resources and LiquidityCash and cash equivalents at end of the period

$
4,380,344

$
3,821,907Net cash provided by (used in) operating activities

$
4,854,720

$
(693,632
)Cash used in investing activities in oil and gas properties, net of divestitures

$
(25,055,809
)
$
(9,407,721
)


Oil and Gas Revenue and Production

During the six month period ended June 30, 2010, as compared to the same period in 2009, crude oil production volumes increased
217% due to new production from completion operations on our Dunn County, North Dakota operating area. Natural gas production volumes decreased 41% due to our decision to limit production on our
Wyoming wells and natural declines in other gas well production. Oil and natural gas revenues increased by $9.0 million, or 328%, for the first half of 2010 compared to the first half of 2009,
primarily due to our increased volumes attributable to our recent well completions and, to a lesser extent, increased realized pricing for oil and natural gas in 2010 versus 2009. The increase in oil
and gas revenue was 83% attributable to the increase in production volumes and 17% attributable to the increase in realized commodity prices.

Lease Operating Expenses

The Company recorded workover, lease operating and production tax expense of approximately $2.7 million during the six month
period ended June 30, 2010, as compared to $492 thousand during the same period in 2009. The increase is due to our increased lease operating expenses on the ten new wells in production
as of June 30, 2010 that were not in production in 2009 and the related severance taxes paid related to the revenue received on the new wells production. A significant portion of the operating
expense is related to the disposal of water in the early months of a well's production. Since a majority of the water is related to completion operations and is largely diminished after two to three
months, the well's operating expenses decline over its early production period. Overall, we have continued to bring new wells online and as a result of the water disposal costs our operating expenses
reflect this added cost.

Depletion, Depreciation and Amortization

DD&A was approximately $2.9 million, for the six month period ended June 30, 2010, compared to $888 thousand for
the same period in 2009. DD&A expense increased during the quarter due to increased production for the new wells placed in service from the second quarter of 2009 through the second quarter of 2010.

Ceiling Test Impairment

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,

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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. For the six months ended June 30, 2010, and June 30, 2009, respectively, no impairment charges
were recorded.

General and Administrative Expense

The Company's general and administrative costs were approximately $4.7 million for the six months ended June 30, 2010
compared to approximately $3.6 million for the same period in 2009. This 31% increase for the period is primarily due to adding additional employees in 2010 as the Company has increased its
operational activities in the Williston Basin. We currently have 27 employees as compared to 16 at the end of 2009. Further, as we have grown our production base in the Williston Basin, we have
established a regional office in Dickinson, North Dakota that is staffed by permanent field employees that directly oversee our ongoing activities.

Oil and Gas Properties

As of June 30, 2010, we had several hundred lease agreements representing approximately 151,000 gross and 82,500 net acres,
primarily in the Green River Basin and Williston Basin.

As
of June 30, 2010, we had an interest in approximately 56,000 gross acres and 35,000 net acres in the Bakken oil play located on the Fort Berthold Indian Reservation in
Mountrail and Dunn Counties, N.D. The majority of our lands in this area are administered by the Bureau of Indian Affairs on behalf of the individual members of the Three Affiliated Tribes of the Fort
Berthold Indian Reservation. Typically, these lands are acquired through a private negotiation with the individual land owners or the
Three Affiliated Tribes and have a primary lease term of five years. 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.

As
of June 30, 2010, we owned an interest in approximately 35,000 gross (22,500 net) acres in the Williston Basin outside the Fort Berthold Indian Reservation in Sheridan County,
Montana, and McKenzie and Divide Counties, North Dakota. This acreage is prospective for Mission Canyon, Red River, Bakken and Three Forks formations.

Our
leasehold interests in the Vermillion Basin total approximately 41,000 gross and 8,800 net acres as of June 30, 2010.

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Table of Contents

The
following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases as of June 30, 2010.

Undeveloped
Acreage(1)

Developed
Acreage(2)

Total AcreageGross

Net

Gross

Net

Gross

NetGreen River BasinWyoming


39,008


9,188


1,520


908


40,528


10,096Colorado


7,339


4,960


0


0


7,339


4,960Williston BasinMontana


16,723


10,606


1,120


507


17,843


11,113North Dakota


64,396


41,418


8,480


4,587


72,876


46,005Other BasinsWyoming


12,042


10,355


0


0


12,042


10,355Acreage Totals


139,508


76,527


11,120


6,002


150,628


82,529


(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 either in 2010 or the following three years and have no options for renewal
or are not included in federal units:

Expiring AcreageYear Ending

Gross

NetDecember 31, 2010


36,556


18,933December 31, 2011


8,836


5,838December 31, 2012


29,787


17,594December 31, 2013


15,509


11,017Total


90,688


53,382


The
acreage expiring in 2010 consists primarily of lands located on the edges of the current drilling activity. We are evaluating some of these lands through our current drilling
program, and we believe we can re-lease these lands as required for development on acceptable terms.

Commitments and Contingencies

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 to September 15, 2010.
The contract can be extended by mutual consent of Kodiak and the drilling contractor at its termination. The estimated termination fee for this first rig is approximately $1.8 million as of
June 30, 2010. The second rig was placed into operation in March 2010 and entails a two-year drilling commitment or specific termination fees if drilling activity is cancelled prior
to March 10, 2012. This

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contract
can also be extended by mutual consent. The estimated termination fee for the second rig is approximately $4.8 million as of June 30, 2010. The Company is currently utilizing
both rigs for drilling in the Williston Basin and expects to continue utilization through their respective terms.

During
the second quarter of 2010, the Company entered into a contract for the use of an additional drilling rig. The third rig is anticipated to be placed into operation in 2011 and
entails a one-year drilling commitment or specific termination fees if the contract is terminated prior to delivery of the rig. It may also be extended by mutual consent. The estimated
termination fee for this third rig is approximately $3.8 million as of June 30, 2010. The Company currently expects to utilize this rig in its operations in the Williston Basin. For a
further discussion of our commitments and contingencies, see Note 5 to our financial statements included above, which is incorporated herein by reference.

Off Balance Sheet Arrangements

The Company did not have any off balance sheet arrangements, as such term is defined in Item 303(a)(4)(ii) of
Regulation S-K, at June 30, 2010 and December 31, 2009.

Critical Accounting Policies and Estimates

Please see Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31,
2009, which is incorporated herein by reference.

Recently Issued Accounting Pronouncements

In January 2010, the FASB issued ASU 2010-03,Extractive ActivitiesOil and Gas (Topic
932),to amend existing oil and gas reserve accounting and disclosure guidance to align its requirements with the SEC's revised rules. 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. In April 2010, the FASB issued ASU 2010-14 which amends the guidance on oil and gas reporting in ASC 932.10.S99-1 by adding the Codification SEC
Regulation S-X, Rule 4-10 as amended by the SEC Final Rule 33-8995. Both ASU 2010-03 and ASU 2010-14 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.

In
January 2010, the FASB issued ASU 2010-06, "Improving Disclosures About Fair Value Measurements", which provides amendments to fair value disclosures. ASU
2010-06 requires additional disclosures and clarifications of existing disclosures for recurring and nonrecurring fair value measurements. The revised guidance for transfers into and out
of Level 1 and Level 2 categories, as well as increased disclosures around inputs to fair value measurement, was adopted January 1, 2010, with the amendments to Level 3
disclosures effective beginning after January 1, 2011. ASU 2010-06 concerns disclosure only. Both the current and future adoption does not have a material impact on the Company's
financial position or results of operations.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

Our primary market risk is market changes in oil and natural gas prices. Prospective revenues from the sale of products or properties
will be impacted by oil and natural gas prices. A $1.00 per Mcf change in the market price of natural gas would have resulted in an approximate $50,805 change in our gross gas production revenue based
on our production volumes for the three months ended June 30,

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2010.
A $1.00 per barrel change in the market price of oil would have resulted in an approximate $81,926 change in our gross oil production revenue based on our production volumes for the three months
ended June 30, 2010.

We
manage this commodity price risk exposure through the use of derivative financial instruments. Currently, we utilize "no premium" collars to reduce the effect of price changes on a
portion of our future oil production. A collar requires us to pay the counterparty if the market price is above the ceiling price and requires the counterparty to pay us if the market price is below
the floor price. At July 31, 2010, forecasted oil production of 200 Bbl/d for the remainder of 2010 and 400 Bbl/d for calendar year 2011 had been hedged.

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 wholly-owned subsidiary,
Kodiak USA, has entered into the derivative contracts with two counterparties, and the Company is a guarantor of Kodiak USA. The Company has netting arrangements with the counterparties that provides
for the offset of payables against receivables from separate derivative arrangements with each 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.

The
objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its
exposure to commodity
price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, these instruments may also limit the Company's ability to benefit from favorable price
movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms
of current contracts in order to realize the current value of the Company's existing positions.

The
Company's commodity derivative contract as of June 30, 2010 is summarized below:

Contract Type

Counterparty

Basis

Quantity(Bbl/d)

Strike Price
($/Bbl)

Term

Fair Value at
June 30, 2010Collar

BP North
America

NYMEX


200

$70.00/$90.00


Mar 1 - Dec 31,
2010

$
47,487


Subsequent to June 30, 2010, the Company entered into an additional commodity derivative contract that is summarized below:

Contract Type

Counterparty

Basis

Quantity(Bbl/d)

Strike Price
($/Bbl)

TermCollar

Wells Fargo

NYMEX


400

$75.00/$89.20


Jan 1 - Dec 31,
2011


Interest Rate Risk

We are exposed to changes in interest rates, which affect the interest earned on our cash and cash equivalents and the interest rate
paid on our borrowings. We have not used interest rate derivative instruments to manage our exposure to interest rate changes.

In
May 2010, the Company (through its wholly-owned subsidiary) entered into a $200 million, four-year, revolving, senior secured credit facility. The outstanding
principal balance of the revolving loan, together with all unpaid fees and expenses relating thereto, shall be due and payable no later than May 24, 2014. As of June 30, 2010, the
Company had borrowed $5.0 million under this credit facility, and as of the time of this filing, the Company had borrowed $7.5 million thereunder.

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Interest
on the revolving loans is payable at the Adjusted LIBO rate for Eurodollar loans, plus a margin based on the daily unused portion of the facility. At June 30, 2010, the
borrowing base for our credit facility was $20 million. Since we had borrowed $5 million under our credit facility at June 30, 2010, we were utilizing 25% of our available
borrowing base. At that level of utilization, our credit facility required us to pay a margin of 2.50% on Eurodollar loans. The all-in interest rate that we were required to pay on the
amounts borrowed under our credit facility under the Eurodollar loan election was 2.86%, as of June 30, 2010. A 10% increase in the rate would equal approximately 29 basis points. Such an
increase would change our annual interest expense by approximately $14,300, assuming borrowed amounts under our credit facility had remained constant at $5 million.

We
also currently maintain a portion of our available cash in redeemable short term investments, classified as cash equivalents, and our reported interest income from these short term
investments could be adversely affected by any material changes in U.S. dollar interest rates. A 10% change in the interest rate would have an approximate annual impact of $391,310 if all of our cash,
as of June 30, 2010, had been invested in interest bearing notes.

ITEM 4.    CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management, we evaluated the effectiveness of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act as of June 30, 2010. On the basis of this review, our Chief Executive Officer and
Chief Financial Officer concluded that our disclosure controls and procedures are effective to give reasonable assurance that the information we are required to disclose in reports that we file or
submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and to ensure that information required to be
disclosed in the reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, in a manner
that allows timely decisions regarding required disclosure.

There
have not been any changes in the Company's internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) promulgated by the
SEC under the Exchange Act) during the Company's most recently completed fiscal quarter that have materially
affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

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PART IIOTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

From time to time, the Company is a party to routine litigation and proceedings that are considered part of the ordinary course of its
business. The Company is not aware of any material current, pending, or threatened litigation.

ITEM 1A.    RISK FACTORS

An investment in our common stock involves a high degree of risk. You should carefully consider the risks
described in this Quarterly Report and the other documents we have filed with the SEC before deciding to invest in our common stock.

This Quarterly Report also contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those
anticipated in the forward-looking statements as a result of a number of factors, including the risks described below and elsewhere in this Quarterly Report. See "Forward-Looking Statements" in this
Quarterly Report.

Risks Related to the Company

Our current working capital, together with cash generated from anticipated production, will not be sufficient to support all our planned exploration and development
opportunities.

Our current working capital, together with cash generated from anticipated production, is only expected to be sufficient to support our
currently anticipated exploration and development opportunities through 2010. If we realize lower than expected cash from production, either due to lower than anticipated production levels or a
decline in commodity prices from recent levels, we would need to curtail our planned exploration and development activities or seek alternative sources of capital, including by means of entering into
joint ventures with other exploration and production companies, sales of interests in certain of our properties or by undertaking additional financing activities (including through the issuance of
equity or the incurrence of debt). We may not be able to access the capital markets or otherwise secure such additional financing on reasonable terms or at all, and financing may not continue to be
available to us under our existing or new financing arrangements. If additional capital resources are unavailable, we may curtail our drilling, development and other activities or be forced to sell
some of our assets on an untimely or unfavorable basis. Any such curtailment or sale could have a material adverse effect on our business, financial condition and results of operation.

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

Operations in the Bakken and the Three Forks formations involve utilizing the latest drilling and completion techniques as developed by
ourselves and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to,
landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and
being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture
stimulate the planned number of stages, being able to run tools the entire length

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of
the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.

Our
experience with horizontal drilling utilizing the latest drilling and completion techniques specifically in the Bakken and Three Forks formations is limited. Ultimately, the success
of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling
results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or
otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of unevaluated
properties and the value of our undeveloped acreage could decline in the future.

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

As of December 31, 2009, approximately 96% of our proved reserves and approximately 67% of our production were located in the
Williston Basin in northeastern Montana and northwestern North Dakota. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused
by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather
conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area. In addition, the effect of fluctuations on supply and
demand may become more pronounced within
specific geographic oil and gas producing areas such as the Williston Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the
concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of
operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition
and results of operations.

The ongoing financial uncertainty in the U. S. and globally could negatively impact the prices for oil and natural gas, limit access to the credit and equity markets and
increase the cost of capital, and may have other negative consequences that we cannot predict.

The ongoing financial uncertainty in the U.S. and globally could create financial challenges if conditions do not improve. Our
internally generated cash flow and cash on hand historically have not been sufficient to fund our expenditures, and we have relied on the capital markets and sales of non-core assets to
provide us with additional capital. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital. If our cash flow from operations is less than
anticipated and our access to capital is restricted, we may be required to reduce our operating and capital budget, which could have a material adverse effect on our results and future operations.
Ongoing uncertainty may also reduce the values we are able to realize in asset sales or other transactions we may engage in to raise capital, thus making these transactions more difficult to
consummate and less economic. Additionally, demand for oil and natural gas may deteriorate and result in lower prices for oil and natural gas, which could have a negative impact on our revenues. Lower
prices could also adversely affect the collectability of our trade receivables and cause our commodity hedging arrangements to be ineffective if our counterparties are unable to perform their
obligations.

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Certain covenants under our credit facility could limit our flexibility and prevent us from taking certain actions. In addition, there can be no assurance that we will be
able to generate sufficient cash flows to repay our debt obligations under our credit facility. The occurrence of any of the foregoing could adversely affect our business, results of operations and
financial condition.

Our new credit facility contains a number of affirmative, negative, and financial covenants that limit our ability to take certain
actions and require us to comply with specified financial ratios and other performance covenants. Such provisions may affect our ability to obtain future financing and pursue attractive business
opportunities and our flexibility in planning for, and reacting to, changes in business conditions. No assurance can be provided that we will not violate the covenants of our secured credit facility
in the future. If we are unable to comply with applicable covenants in the future, our lender could pursue its contractual remedies under the credit facility,
including requiring the immediate repayment in full of all amounts outstanding and foreclosing on the oil and gas properties mortgaged to our lender. Additionally, we cannot be certain that, if the
lender demands immediate repayment of any amounts outstanding, we would be able to secure adequate or timely replacement financing on acceptable terms or at all.

Availability under our credit facility is based on a borrowing base which is subject to redetermination by our lenders. If our borrowing base is reduced, we may be required
to repay amounts outstanding under our credit facility.

Our ability to make payments due under our credit facility will depend upon our future operating performance, which is subject to
general economic and competitive conditions and to financial, business and other factors, many of which we cannot control. In addition, our borrowing base is subject to semi-annual
redetermination by our lender based on its valuation of our proved reserves and the lender's internal criteria. In the event the amount outstanding under our credit facility at any time exceeds the
borrowing base at such time, we may be required to repay a portion of our outstanding borrowings on an accelerated basis. If we do not have sufficient funds on hand for repayment in such event, or to
service our debt obligations generally, we may be required to seek a waiver or amendment from our lenders, refinance our credit facility, sell assets or sell additional shares of securities. We may
not be able obtain such financing or complete such transactions on terms acceptable to us, or at all. In addition, our credit agreement may limit our ability to take certain of such actions. Failure
to make the required repayment could result in a default under our credit facility. Our failure to generate sufficient funds to pay our debts or to undertake any of these actions successfully, or to
comply with the covenants under our credit facility mentioned above, could materially adversely affect our business, results of operations and financial condition.

We may incur termination fees related to our drilling rig contracts, which could impair our working capital and have a material adverse effect on our business, operations
and liquidity.

We
have three contracts currently in place for the use of drilling rigs. As of May 31, 2010, the estimated termination fees are approximately
$2.5 million for the first rig contract that expires in September 2010, approximately $4.9 million for the second rig contract that expires in March 2012 and approximately
$3.8 million for the third rig contract that expires in October 2011. If we incur any of these fees as a result of terminating one or more of the drilling rig contracts, our working capital
could be impaired. Such event could accelerate the need we may have for additional capital funding and may adversely affect our ability to comply with our credit facility covenants and/or result in a
decrease in our borrowing base, which could result in the acceleration of our debt repayment obligations. Any of such events could have a material adverse effect on our business, operations and
liquidity.

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

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



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

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

From time to time, we enter into financial hedge arrangements (commodity derivative agreements) in order to manage our commodity price
risk and to provide a more predictable cash flow from operations. We do not intend to designate our derivative instruments as hedges for accounting purposes. The fair value of our derivative
instruments will be marked to market at the end of each quarter and the resulting unrealized gains or losses due to changes in the fair value of our derivative instruments will be recognized in
current earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

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

Derivative
instruments also expose us to the risk of financial loss in some circumstances, including when:



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

We intend to continue to place hedges on future production and if we encounter difficulties meeting that production, we may not realize the originally anticipated cash
flows.

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

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

We have historically incurred losses from operations during our history in the oil and natural gas business. As of June 30,
2010, we had a cumulative deficit of $104 million. While we have developed some of our properties, many of our properties are in the exploration stage, and to date we have established a limited
volume of proved reserves on our properties. Our ability to be profitable in the future will depend on successfully implementing our acquisition, exploration, development and production activities,
all of which are subject to many risks beyond our control. We cannot assure you that we will successfully implement our business plan or that we will achieve commercial profitability in the future.
Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis. In addition, should we be unable to continue as a
going concern, realization of assets and settlement of liabilities in other than the normal course of business may be at amounts significantly different from those in the financial statements included
in our most recently filed annual report on Form 10-K for the year ended December 31, 2009 and quarterly report on Form 10-Q for the quarter ended
June 30, 2010.

The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net revenues from our proved
reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

Our most recently filed annual report on Form 10-K contains estimates of our proved oil and natural gas reserves and
the estimated future net revenues from these reserves. The December 31, 2009 reserve estimate was prepared by Netherland Sewell & Associates, Inc. The process of estimating oil
and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir.
Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and
natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our
proved reserves. In addition,

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we
may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and
natural gas prices and other factors, many of which are beyond our control.

You
should not assume that the present value of future net revenues referred to in our annual report on Form 10-K is the current market value of our estimated oil and
natural gas reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved
reserves are generally based on the un-weighted average of the closing prices during the first day of each of the twelve months preceding the end of the fiscal year. Actual future prices
and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any change in consumption by oil or natural gas purchasers or in governmental regulations or
taxation will also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of our oil and natural gas properties will affect the
timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net
cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it reflect discount factors used in the market place for the purchase and sale of oil and natural
gas.

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

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

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

We have not insured and cannot fully insure against all risks and have not attempted to insure fully against risks where coverage is
prohibitively expensive. Our exploration, drilling and other activities are subject to risks such as:



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

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financial
condition and results of operations. In addition, weather conditions and other events could temporarily impair our ability to transport our oil and natural gas production.

We
do not carry business interruption insurance coverage. Losses and liabilities arising from uninsured and underinsured events, which could arise from even one catastrophic accident,
could materially and adversely affect our business, results of operations and financial condition.

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

We do not operate all of the properties in which we have an interest. As a result, we may have a limited ability to exercise influence
over normal operating procedures, expenditures or future development of underlying properties and their associated costs. For all of the properties that are operated by others, we are dependent on
their decision-making with respect to day-to-day operations over which we have little control. The failure of an operator of wells in which we have an interest to adequately
perform operations, or an operator's breach of applicable agreements, could reduce production and revenues we receive from that well. The success and timing of our drilling and development activities
on properties operated by others depend upon a number of factors outside of our control, including:



In
particular, we are party to a joint venture agreement with a third party that relates to the development of certain of our properties in Dunn County, North Dakota. Pursuant to this
agreement, we are required to pay 50% of the drilling expenses attributable to our joint venture's proportionate interest incurred in the area of mutual interest. In 2010, we allocated
$12 million of our capital budget toward the payment of these drilling expenses. We have recently been advised by our joint venture partner that it intends to add a second drilling rig in 2011,
which would require us to make significantly higher capital contributions to satisfy our proportionate share of the exploration costs. If such capital contributions are required, we may not be able to
obtain the financing necessary to satisfy our obligations or we may have to reallocate our anticipated capital expenditure budget. In the event that we do not participate in future capital
contributions with respect to this joint venture agreement or any other agreements relating to properties we do not operate, our respective ownership interest could be diluted.

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

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

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

During the year ended December 31, 2009, over 55% of our oil production was sold to one customer. We also sell our production to
a number of other customers, and we believe that those customers, along with other purchasers, would purchase all or substantially all of our production in the event that our major customer curtailed
its purchases. It is possible that one or more of our customers will become financially distressed and default on their obligations to the Company. Furthermore, bankruptcy of one or more of our
customers, or some other similar procedure, might make it difficult for us to collect all or a significant portion of amounts owed by the customers. Our inability to collect our accounts receivable
could have a material adverse effect on our results of operations.

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

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

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

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

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

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Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the
properties or obtain protection from sellers against them, which could cause us to incur losses. Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may
create additional economic risk.

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

Our
success is largely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As of December 31,
2009, approximately 68% of our total proved reserves were undeveloped. To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient
funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. In addition, delays in the development of our reserves or
increases in costs to drill and develop such reserves will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may
result in some projects becoming uneconomic.

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

As of June 30, 2010, we had $5 million borrowed under a credit facility. Subsequent to June 30, we borrowed an
additional $2.5 million under this credit facility, and we may borrow additional amounts in the future. Our credit facility is subject to a floating interest rate, which may vary in line with
the movements in short term interest rates. As a result, our interest expenses may increase significantly if short term interest rates increase. To the extent that we rely on our credit facility, an
increase in the interest rate under our facility would increase the borrowing cost of our outstanding debt.

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

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

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

Some of our directors and officers may also become directors, officers, contractors, shareholders or employees of other companies
engaged in oil and natural gas exploration and development. To the extent that such other companies may participate in ventures in which we may participate, our directors

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

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

Exploratory drilling is a speculative activity that may not result in commercially productive reserves and may require expenditures in excess of budgeted amounts.

Our future rate of growth greatly depends on the success of our exploratory drilling program. Exploratory drilling involves a higher
degree of risk that we will not encounter commercially productive oil or natural gas reservoirs than developmental drilling. We may not be successful in our future drilling activities because, even
with the use of advanced horizontal drilling and completion techniques, 3-D seismic and other advanced technologies, exploratory drilling is a speculative activity.

Marketing and transportation constraints in the Williston Basin could adversely affect our operations and result in significant fluctuations in our realized prices for oil
and, to a lesser extent, natural gas.

We deliver oil and natural gas through gathering systems and pipelines that we do not own. These facilities may not be available to us
in the future. In particular, the Williston Basin crude oil marketing and transportation environment has historically been characterized by periods when oil production has surpassed local
transportation and refining capacity. These factors could force us to shut-in producing wells, delay the commencement of production, or discontinue development plans for some of our
properties. In addition, these factors have resulted, and could continue to result, in substantial discounts in the price received for crude oil compared to benchmark prices, such as the West Texas
Intermediate crude oil prices. The persistence of such constraints could have a material adverse effect on our financial condition and results of operations.

We are subject to the risks associated with our prior business activities.

Additional risks may exist because of our prior business activities. Prior to current management's acquisition of control of
substantially all of our common stock, we engaged in a number of businesses, including mining operations and marketing of fire retardant operations. For a period of years prior to current management's
acquisition of control of us, we had no business operations. Although current management performed a due diligence review, we may still be exposed to undisclosed liabilities, including environmental
liabilities, resulting from the prior operations of our company and we could incur losses, damages or other costs as a result.

Our competitors include larger, better financed and more experienced companies.

The oil and natural gas industry is intensely competitive, and we must compete against larger companies that may have greater financial
and technical resources than us and substantially more

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experience
in our industry. Their competitive advantages may negatively impact our ability to acquire prospective properties, develop reserves, attract and retain quality personnel and raise capital.
Their competitive advantages may also better enable our competitors to sustain the impact of higher exploration and production costs, oil and natural gas price volatility, productivity variances among
properties, overall industry cycles and other factors related to our industry.

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

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

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

As of June 30, 2010, we had $5 million borrowed under a credit facility. Subsequent to June 30, 2010, we borrowed
an additional $2.5 million under this credit facility, which has an initial borrowing capacity of $20 million. In the future, we may incur significant indebtedness in order to make
future acquisitions or to develop our properties.

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



A
high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on
our future performance. General economic conditions, oil and natural gas prices and financial, business and other

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factors
affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future
working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a
refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In
addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base.
If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new
financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

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

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



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

Significant
acquisitions and other strategic transactions may involve other risks, including:



The
process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote
considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration
process, or if any

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significant
business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.

The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from
combining the acquired assets or operations with those of ours. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves,
production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an
acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory
prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of
operations may be adversely affected.

Risks Relating to Our Industry

Oil and natural gas prices are volatile. A substantial or extended decline in oil prices and, to a lesser extent, natural gas prices, could adversely affect our financial
position, financial results, cash flows, access to capital and ability to grow.

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

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



Wide
fluctuations in natural gas and oil prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and other factors that
are beyond our control, including:



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Volatile
oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas
producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and
exploitation projects.

Our
revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas, that we sell. Prices
also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. In addition, we may need to record asset carrying value write-downs
if prices fall, as was the case in 2008 and 2007. A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to
capital and ability to grow.

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

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



Lower
oil and natural gas prices may not only decrease revenues on a per unit basis, but also may reduce the amount of oil and natural gas that can be economically produced. Lower prices
will also negatively affect the value of proved reserves.

To
attempt to reduce our price risk, in 2010, we implemented a strategy to hedge a portion of our expected future production. We cannot assure you that such transactions will reduce the
risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil would have a material adverse effect on our financial
condition and results of operations.

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

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to
acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a "full cost ceiling"
which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value
of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the
excess to earnings in the period then ended. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our net income and
stockholders' equity. During 2009 and 2008, we recognized approximately $0 and $47.5 million, respectively, in ceiling test write-downs. We may recognize write-downs in the future if commodity
prices continue to decline or if we experience substantial downward adjustments to our estimated proved reserves.

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

Companies that explore for and develop, produce and sell oil and natural gas in the United States are subject to extensive federal,
state and local laws and regulations, including complex tax and environmental laws and the corresponding regulations, and are required to obtain various permits and approvals from federal, state and
local agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our drilling activities, we may not be able to conduct our operations as planned. We may be
required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:



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

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The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

In 2010, we implemented a strategy to hedge a portion of our crude oil and natural gas production. Congress is currently considering
legislation to impose restrictions on certain transactions involving derivatives, which could affect the use of derivatives in hedging transactions. The proposed legislation contains provisions that
would prohibit private energy commodity derivative and hedging transactions by expanding the power of the Commodity Futures Trading Commission, or CFTC, to regulate derivative transactions related to
energy commodities, including natural gas and oil, and to mandate clearance of such derivative contracts through registered derivative clearing organizations. Under the proposed legislation, the
CFTC's expanded authority over energy derivatives would terminate upon the adoption of general legislation covering derivative regulatory reform. The CFTC is considering whether to set limits on
trading and positions in commodities with finite supply, particularly energy commodities, such as crude oil, natural gas and other energy products. The CFTC also is evaluating whether position limits
should be applied consistently across all markets and participants. Although it is not possible at this time to predict whether or when Congress may act on derivatives legislation, any laws or
regulations that may be adopted that subject us to additional capital or margin requirements relating to, or additional restrictions on, our trading and commodity positions could have an adverse
effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

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

Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state, local and tribal
laws and regulations governing health and safety
aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations include, but are not limited to, the federal
Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and
Liability Act, the Safe Drinking Water Act, the Occupational Safety and Health Act and their state counterparts and similar statutes, which provide for civil, criminal and administrative penalties and
other sanctions for violation of their requirements.

These
laws and regulations may impose numerous obligations on us and our operations including by requiring us to obtain permits before conducting drilling or underground injection
activities; restricting the types, quantities and concentration of materials that we can release into the environment; limiting or prohibiting drilling activities on certain lands lying within
wilderness, wetlands and other protected areas; subjecting us to specific health and safety requirements addressing worker protection; imposing substantial liabilities on us for pollution resulting
from our operations; and requiring us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.
Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and
the permits issued under them, and their interpretation and enforcement of these laws, regulations and permits have tended to become more stringent over time. Failure to comply with these laws,
regulations and permits may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory, remedial or monitoring obligations; and the issuance of
injunctions limiting or prohibiting some or all of our operations.

There
is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations because of our handling of petroleum hydrocarbons and wastes; air
emissions and wastewater discharges related to our operations; our ownership, lease or operation of real property;

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

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

Through its comprehensive new regulatory regime for derivatives, the Dodd-Frank Act will impose mandatory clearing,
exchange-trading and margin requirements on many derivatives transactions (including formerly unregulated over-the-counter derivatives) in which we may engage. The
Dodd-Frank Act also creates new categories of regulated market participants who will be subject to significant new capital, registration, recordkeeping, reporting, disclosure, business
conduct and other regulatory requirements. The details of these requirements and the parameters of these categories remain to be clarified through rulemaking and interpretations by the CFTC, the SEC,
the Federal Reserve and other regulators in a regulatory implementation process which is expected to take a year or more to complete.

Nonetheless,
based on information available as of the date of this prospectus, the possible effect of the Dodd-Frank Act will be to increase our overall costs of entering
into derivatives transactions. In particular, new margin requirements, position limits and capital charges, even if not directly applicable to us, may cause an increase in the pricing of derivatives
transactions sold by market participants to whom such requirements apply. Administrative costs, due to new requirements such as registration, recordkeeping, reporting, and compliance, even if not
directly applicable to us, may also be reflected in higher pricing of derivatives. New exchange-trading and trade reporting requirements may lead to reductions in the liquidity of derivative
transactions, causing higher pricing or reduced availability of derivatives, adversely affecting the performance of our hedging strategies.

The
Dodd-Frank Act could result in the cost of executing our hedging strategy increasing significantly, which could potentially result in an undesirable decrease in the
amount of oil production we hedge. If our hedging costs increase and we are required to post cash collateral, our business would be adversely affected as a result of reduced cash flow and reduced
liquidity. Additionally, in the event that we hedge lower quantities in response to higher hedging costs and increased margin requirements, our exposure to changes in commodity prices would increase,
which could result in decreased cash flows.

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

Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used
by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock

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formations
to stimulate natural gas production. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for
third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In
addition, such legislation, if adopted, or similar requirements at the state or local level, could lead to operational delays or increased operating costs and could result in additional regulatory
burdens, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and doing business.

Changes in tax laws may impair our results of operations and adversely impact the value of our common stock.

In February 2009, the Obama administration released its budget proposals for the fiscal year 2010, which included numerous proposed tax
changes. In April 2009, legislation was introduced to further these objectives, and in February 2010, the Obama administration released similar budget proposals for the fiscal year 2011. Among the
changes contained in the budget proposals is the elimination of certain key U.S. federal income tax preferences currently available to oil and gas exploration and production companies. These changes
include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and
development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) the repeal of the passive loss exception for working interests in oil and gas
properties. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and
regulations could adversely affect the amount of our taxable income or loss and could have a negative impact on the value of our common stock.

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

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

Existing
and possible future environmental legislation, regulations and actions, including those related to climate and emissions of "greenhouse gases," could give rise to additional
expenses, capital expenditures, restrictions and delays in our activities, the extent of which we cannot predict. In addition, climate change laws and regulations may adversely affect demand for the
fossil fuels we produce, including by increasing the cost of combusting fossil fuels and by creating incentives for the use of alternative fuels and energy. Regulatory requirements and environmental
standards are subject to constant evaluation and may be significantly increased, which could materially and adversely affect our business or our ability to develop our properties on an economically
feasible basis. Before development and production can commence on any properties, we must obtain regulatory and environmental approvals. We cannot assure you that we will obtain such approvals on a
timely basis or at all. The cost of compliance with changes in governmental regulations has the potential to reduce the profitability of our operations and preclude entirely the economic development
of a specific property.

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

Oil and natural gas exploration is intensely competitive and involves a high degree of risk. In our efforts to acquire oil and natural
gas producing properties, we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also conduct refining and
petroleum marketing operations on a worldwide basis. Our ability to compete for oil and natural gas producing properties will be affected by the amount of funds available to us, information available
to us and any standards established by us for the minimum projected return on investment. Our products will also face competition from alternative fuel sources and technologies.

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

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

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

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel.
During these periods, the costs and delivery times of rigs, equipment and supplies tend to increase, in some cases substantially. In addition, the demand for, and wage rates of, qualified drilling rig
crews rise as the number of active rigs in service increases within a geographic area. If increasing levels of exploration and production result in response to strong prices of oil and natural gas,
the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of
drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in the areas in which we operate, we could be materially and adversely affected.

Risks Relating to Our Common Stock

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

On July 14, 2008, we filed a shelf registration statement on Form S-3 (SEC file
No. 333-152311), which was declared effective by the SEC on July 24, 2008. Under this shelf registration statement, we have raised funds and may seek to raise additional
funds through one or more public offerings of our common stock, in amounts and at prices and terms determined at the time of the offering. Any sales of large quantities of our common stock could
reduce the price of our common stock, and, to the extent that we raise additional capital by
issuing equity securities pursuant to our effective shelf registration statements or otherwise, our existing stockholders' ownership will be diluted.

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

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

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September 28,
2001. The price of our common stock may be impacted by any of the following, some of which may have little or no relation to our company or industry:



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

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

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

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

Our Articles of Continuation permit us to issue an unlimited number of shares of our common stock. Subject to the requirements of any
exchange on which we may be listed, we will not be required to obtain the approval of shareholders for the issuance of additional shares of our common stock. In 2005, we issued 20,671,875 shares of
our common stock for net proceeds of $17,879,673. In 2006, we issued 31,589,268 shares of our common stock for net proceeds of $83,209,451. In 2008, we issued 6,820,000 shares of our common stock for
net proceeds of $17,471,488. In 2009 we issued 23,400,000 shares of our common stock for net proceeds of $35,731,122. Any further issuances of shares of our common stock from our treasury will result
in immediate dilution to existing shareholders and may have an adverse effect on the value of their shareholdings.

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

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

ITEM 2.    UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.    DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.    RESERVED

ITEM 5.    OTHER INFORMATION

None.

ITEM 6.    EXHIBITS

Exhibit
Number

Description10.1

Purchase and Sale Agreement between Macquarie Barnett, LLC and Kodiak Oil & Gas (USA) Inc.31.1

Certification of the Principal Executive Officer pursuant to §302 of the Sarbanes-Oxley Act of 200231.2

Certification of the Principal Financial Officer pursuant to §302 of the Sarbanes-Oxley Act of 200232.1

Certification of the Principal Executive Officer pursuant to 18 U.S.C. Section 135032.2

Certification of the Principal Financial Officer pursuant to 18 U.S.C. Section 1350


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Table of Contents

SIGNATURES

Pursuant to the requirements 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.August 5, 2010



/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive OfficerAugust 5, 2010



/s/ JAMES P. HENDERSON James P. Henderson Chief Financial Officer
(principal financial officer)


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