Use these links to rapidly review the documentTABLE OF CONTENTS

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 1934For the quarterly period ended March 31, 2011


Commission File No. 001-32920

LOGO

(Exact name of registrant as specified in its charter)

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

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


1625 Broadway, Suite 250
Denver, Colorado 80202(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

179,177,939 shares, no par value, of the Registrant's common stock were issued and outstanding as of May 3, 2011.



---





Table of Contents



KODIAK OIL & GAS CORP.

INDEX



PART 1FINANCIAL INFORMATION

2ITEM 1.

FINANCIAL STATEMENTS (UNAUDITED)

2ITEM 2.

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

19ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

30ITEM 4.

CONTROLS AND PROCEDURES

31PART IIOTHER INFORMATION

32ITEM 1.

LEGAL PROCEEDINGS

32ITEM 1A.

RISK FACTORS

32ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

32ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

32ITEM 4.

RESERVED

32ITEM 5.

OTHER INFORMATION

32ITEM 6.

EXHIBITS

33SIGNATURES

34


1

---





Table of Contents



PART 1FINANCIAL INFORMATION



ITEM 1.    FINANCIAL STATEMENTS

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED BALANCE SHEETS        (In thousands, except share data)        (Unaudited)

March 31,
2011

December 31,
2010ASSETSCurrent AssetsCash and cash equivalents

$
76,155

$
101,198Accounts receivableTrade


9,854


11,328Accrued sales revenues


4,566


4,578Inventory, prepaid expenses and other


21,935


18,212Total Current Assets


112,510


135,316Oil and gas properties (full cost method), at costProved oil and gas properties


213,019


205,360Unproved oil and gas properties


112,061


107,254Wells in progress


41,697


21,418Equipment and facilities


2,864


2,429Less-accumulated depletion, depreciation, amortization, accretion and asset impairment


(107,442
)

(103,799
)Net oil and gas properties


262,199


232,662Property and equipment, net of accumulated depreciation of $409 at March 31, 2011 and $377 at December 31, 2010


517


366Deferred financing costs, net of amortization of $187 at March 31, 2011 and $83 at December 31, 2010


1,423


1,593Total Assets

$
376,649

$
369,937LIABILITIES AND STOCKHOLDERS' EQUITYCurrent LiabilitiesAccounts payable and accrued liabilities

$
24,485

$
23,179Commodity price risk management liability


6,256


2,248Total Current Liabilities


30,741


25,427Noncurrent LiabilitiesLong term debt


40,000


40,000Commodity price risk management liability


8,838


3,495Asset retirement obligation


2,179


1,968Total Noncurrent Liabilities


51,017


45,463Total Liabilities


81,758


70,890Commitments and ContingenciesNote 5Stockholders' Equity:Common stockno par value; unlimited authorized Issued and outstanding: 179,127,939 shares as of March 31, 2011 and 178,168,205 shares as of
December 31, 2010 Contributed surplus


410,391


407,312Accumulated deficit


(115,500
)

(108,265
)Total Stockholders' Equity


294,891


299,047Total Liabilities and Stockholders' Equity

$
376,649

$
369,937


THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

2

---





Table of Contents

KODIAK OIL & GAS CORP.        CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS        (In thousands, except share data)        (Unaudited)

Three months ended March 31,2011

2010RevenuesOil production

$
13,020

$
5,488Gas production


314


233Other income


103


Total revenues


13,437


5,721Operating expensesOil and gas production


2,574


1,222Depletion, depreciation, amortization and accretion


3,721


1,321General and administrative


4,718


2,085Total expenses


11,013


4,628Operating income


2,424


1,093Other income (expense)Loss on commodity price risk management activities


(9,692
)

(122
)Interest income (expense), net


33


10Total financing and other costs


(9,659
)

(112
)Net income (loss)

$
(7,235
)
$
981Earnings per common share:Basic

$
(0.04
)
$
0.01Diluted

$
(0.04
)
$
0.01Weighted average common shares outstanding:Basic


178,451,574


118,931,087Diluted


178,451,574


120,588,940


THE
ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

3

---





Table of Contents

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

For the three months
ended
March 31,2011

2010Cash flows from operating activities:Net income (loss)

$
(7,235
)
$
981Reconciliation of net income (loss) to net cash provided by operating (used in) activities:Depletion, depreciation, amortization and accretion


3,721


1,321Unrealized loss on commodity price risk management activities, net


9,350


122Stock based compensation


1,539


854Changes in current assets and liabilities:Accounts receivable-trade


1,474


(3,033
)Accounts receivable-accrued sales revenue


12


(1,698
)Prepaid expenses and other


(295
)

(530
)Accounts payable and accrued liabilities


(1,414
)

(424
)Net cash provided by (used in) operating activities


7,152


(2,407
)Cash flows from investing activities:Oil and gas properties


(22,423
)

(7,447
)Prepaid tubular goods


(10,084
)

(4,287
)Equipment, facilities, & other


(618
)

(81
)Restricted investment





(210
)Net cash used in investing activities


(33,125
)

(12,025
)Cash flows from financing activities:Proceeds from the issuance of common shares


947


113Debt issuance costs


(17
)

Net cash provided by financing activities


930


113Decrease in cash and cash equivalents


(25,043
)

(14,319
)Cash and cash equivalents at beginning of the period


101,198


24,886Cash and cash equivalents at end of the period

$
76,155

$
10,567Supplemental cash flow informationOil & gas property accrual included in Accounts payable and accrued liabilities

$
11,589

$
1,021Asset retirement obligation

$
165

$
175Cash paid for interest

$
1,124

$



THE
ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE
FINANCIAL STATEMENTS

4

---





Table of Contents

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

Note 1Organization

Description of Operations

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

The
Company was incorporated (continued) in the Yukon Territory on September 28, 2001.

Note 2Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements include the accounts of the Company and its wholly-owned
subsidiary, Kodiak Oil & Gas (USA) Inc. All significant inter-company balances and transactions have been eliminated in consolidation. The majority of the Corporation's business is
transacted in US dollars and, accordingly, the financial statements are expressed in US dollars.

Use of Estimates in the Preparation of Financial Statements

The financial statements included herein were prepared from the records of the Company in accordance with generally accepted accounting
principles in the United States ("GAAP") 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. 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.

As
of March 31, 2011 and December 31, 2010, the Company had approximately $50.5 million in money market accounts with its bank. The money market accounts are limited
to six withdrawals per month; however, there are no other redemption restrictions. Therefore, the Company classified the entire balance as Cash and Cash Equivalents at March 31, 2011.

5

---



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)

Accounts Receivable

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects
costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible
receivables under the specific identification method. The Company did not record any allowance for uncollectible receivables as of March 31, 2011 or December 31, 2010.

Inventory, Prepaid Expenses and Other

Included in inventory, prepaid expenses and other are deposits made on orders of tubular goods required for the Company's drilling
program. As of March 31, 2011 there was approximately $5.6 million in deposits made and recorded. As of December 31, 2010 there was approximately $7.6 million in deposits
made and recorded. In respect of the $5.6 million tubular goods deposit as of March 31, 2011, the Company estimates that an additional $5.6 million will be paid to
complete the purchase and the deposits would be subject to forfeiture if the purchases are not completed. The cost basis of the tubular goods is depreciated as a component of oil and gas properties
once the inventory is used in drilling operations. At March 31, 2011 and December 31, 2010 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.

Concentration of Credit Risk

The Company's cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages
and controls this risk by investing these funds with major financial institutions. The Company may at times have balances in excess of the federally insured limits.

The
Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the
collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, 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, 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 audited by independent petroleum engineers. Costs included in the depletion base to be amortized include (a) all proved
capitalized costs including

6

---



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)

capitalized
asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and
(c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset
retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are
reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to
depletion calculations.

Estimated
reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company's
overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company's proved properties.

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

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

Depletion and Impairment of Proved Oil and Gas Properties

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. The cost of acquiring and evaluating unproved properties are initially excluded from 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,

7

---



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)

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. Should
capitalized costs exceed this ceiling, a write-down is recognized. The present value of estimated future net revenues was computed by applying twelve month average first of month prices of
oil and gas to estimated future production of proved oil and gas reserves as of period-end (in both 2010 and 2011), 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 write-down recognized as of March 31, 2011
or for the year ended December 31, 2010.

Impairment of Unproved Oil and Gas Properties

The Company's unproved properties are evaluated quarterly for the possibility of potential impairment. As of March 31, 2011 and
for the year ended December 31, 2010, no impairment was recorded.

Deferred Financing Costs

As of March 31, 2011, the Company recorded deferred financing costs of $1.4 million 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 $187,000 as of March 31, 2011. The Company recorded amortization expense of $83,000 (which
included the expensing of all remaining deferred financing costs from the Company's previous credit facility) as of December 31, 2010.

Capitalization of Interest

The Company capitalizes interest costs associated with the development and construction of significant properties or projects to bring
them to a condition and location necessary for their intended use, which, for crude oil and natural gas assets, is at first production from the field. Interest is capitalized using an interest rate
equivalent to the average rate we pay on our note payable. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a
unit-of-production basis. Capitalized interest totaled $1.1 million as of March 31, 2011 and $470,000 in 2010.

8

---



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)

Commodity Derivative Instrument

Through its wholly-owned subsidiary Kodiak Oil & Gas (USA) Inc., the Company has entered into commodity derivative
contracts, as described below. The Company has utilized swaps or "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. A swap requires us to pay the counterparty if the
settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. 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, 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 one counterparty and the Company is a guarantor of Kodiak USA. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables
from separate derivative arrangements with the counterparty in the event of contract termination. 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 contracts as of March 31, 2011 are summarized below:

Contract Type

Counterparty

Basis(1)

Quantity(Bbl/d)

Strike Price ($/Bbl)

TermCollar

Wells Fargo Bank, N.A.

NYMEX

400

$75.00/$89.20

Jan 1 - Dec 31, 2011Collar

Wells Fargo Bank, N.A.

NYMEX

200 - 500

$70.00/$95.56

Jan 1 - Dec 31, 2011Collar

Wells Fargo Bank, N.A.

NYMEX

400

$85.00/$117.73

Mar 1 - Dec 31, 2011Collar

Wells Fargo Bank, N.A.

NYMEX

400

$70.00/$95.56

Jan 1 - Dec 31, 2012Collar

Wells Fargo Bank, N.A.

NYMEX

230

$85.00/$117.73

Jan 1 - Dec 31, 2012


9

---



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)



Contract Type

Counterparty

Basis(1)

Quantity(Bbl/d)

Swap Price ($/Bbl)

TermSwap

Wells Fargo Bank, N.A.

NYMEX


135

$
84.00

Jan 1 - Dec 31, 2011Swap

Wells Fargo Bank, N.A.

NYMEX


130

$
90.28

Jul 1 - Dec 31, 20112011 Total/Average






201

$
85.85Swap

Wells Fargo Bank, N.A.

NYMEX


100

$
84.00

Jan 1 - Dec 31, 2012Swap

Wells Fargo Bank, N.A.

NYMEX


136

$
88.30

Jan 1 - Dec 31, 2012Swap

Wells Fargo Bank, N.A.

NYMEX


24

$
90.28

Jan 1 - Dec 31, 20122012 Total/Average






260

$
86.83Swap

Wells Fargo Bank, N.A.

NYMEX


79

$
84.00

Jan 1 - Dec 31, 2013Swap

Wells Fargo Bank, N.A.

NYMEX


427

$
88.30

Jan 1 - Dec 31, 2013Swap

Wells Fargo Bank, N.A.

NYMEX


24

$
90.28

Jan 1 - Dec 31, 20132013 Total/Average






530

$
87.75Swap

Wells Fargo Bank, N.A.

NYMEX


69

$
84.00

Jan 1 - Dec 31, 2014Swap

Wells Fargo Bank, N.A.

NYMEX


360

$
88.30

Jan 1 - Dec 31, 2014Swap

Wells Fargo Bank, N.A.

NYMEX


21

$
90.28

Jan 1 - Dec 31, 20142014 Total/Average






450

$
87.73Swap

Wells Fargo Bank, N.A.

NYMEX


59

$
84.00

Jan 1 - Oct 31, 2015Swap

Wells Fargo Bank, N.A.

NYMEX


317

$
88.30

Jan 1 - Sept 30, 2015Swap

Wells Fargo Bank, N.A.

NYMEX


46

$
90.28

Jan 1 - Oct 31, 20152015 Total/Average (Through October)






390

$
87.81


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


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

Underlying Commodity

Location on
Balance Sheet

March 31,
2011

December 31,
2010Crude oil derivative contract

Current liabilities

$
6,256

$
2,248Crude oil derivative contract

Noncurrent liabilities

$
8,838

$
3,495


The
amount of gain (loss) recognized in income related to our derivative financial instruments was as follows (in thousands):

For the three
months ended
March 31, 2011

For the three
months ended
March 31, 2010Unrealized loss on oil contracts

$
(9,350
)
$
(122
)Realized loss on oil contracts

$
(342
)

Loss on commodity price risk management activities

$
(9,692
)
$
(122
)


Unrealized
gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized on the consolidated statement
of operations. Both the unrealized and realized gains and losses resulting from the contract settlement of

10

---



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)

derivatives
are recorded in the commodity price risk management activities line on the consolidated statement of income.

Fair Value of Financial Instruments

The Company's financial instruments, other than the derivative instruments discussed above, including cash and cash equivalents,
accounts payable and accrued liabilities are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Additionally, the recorded value of the
Company's long-term debt approximates its fair value as it bears interest at variable rates over the term of the loan.

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.

Revenue Recognition

The Company records revenues from the sales of natural gas and crude oil when they are produced. The Company may have an interest with
other producers in certain properties, in which case the Company uses the sales method to account for gas imbalances. Under this method, revenue is recorded on the basis of gas actually sold by the
Company. In addition, the Company records revenue for its share of gas sold by other owners that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company
also reduces revenue for other owners' gas sold by the Company that cannot be volumetrically balanced in the future due to insufficient remaining reserves. The Company's over and under produced gas
balancing positions are considered in the Company's proved oil and gas revenues. Gas imbalances at March 31, 2011, and December 31, 2010 were not significant.

Asset Retirement Obligation

The Company follows accounting for asset retirement obligations in accordance with ASC 410, which requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included
in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the
asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and
abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are included in the ceiling test

11

---



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)

calculation.
Asset retirement obligations are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is accreted to its present value each period
and the capitalized costs are depreciated using a systematic and rational method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company's
Condensed Consolidated Statement of Operations. As of March 31, 2011, and December 31, 2010, the Company has recorded a net asset of $1.4 million and $1.3 million and a
related liability of $2.2 million and $2.0 million, respectively.

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

(In thousands)For the three
months ended
March 31, 2011

For the Year Ended
December 31, 2010Balance beginning of period

$
1,968

$
1,060Liabilities incurred


165


849Liabilities settled





(67
)Accretion expense


46


126Balance end of period

$
2,179

$
1,968


Note 3Wells in Progress

The following table reflects the net changes in capitalized additions to wells in progress during the three months ended March 31, 2011 and the year ended December 31,
2010, and includes amounts that were capitalized and reclassified to producing wells in the same periods (in thousands).

For the three
months ended
March 31, 2011

For the Year
Ended
December 31, 2010Beginning balance

$
21,418

$
2,691Additions to capital wells in progress costs pending the determination of proved reserves


23,218


36,257Reclassifications to wells, facilities, and equipment based on the determination of proved reserves to full cost pool


(2,939
)

(17,530
)Ending balance

$
41,697

$
21,418


As
of March 31, 2011, wells in progress included nine gross (6.4 net) operated and eleven gross (2.4 net) non-operated wells in the Williston Basin. Two of the nine
operated wells classified as wells-in-progress as of March 31, 2011 were completed in April 2011 and a third is scheduled for completion in May 2011. The remaining
operated wells are part of multi-well pads and are expected to be completed in 2011.

12

---



Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Share-Based Payments

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 share-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 million shares to 16.6 million shares through December 31, 2010. Beginning in
2011, the maximum number 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. As of
March 31, 2011, the Company has outstanding options to purchase 5.8 million common shares at prices from $0.36 to $7.20 per share.

The
Company granted stock options to acquire 640,000 common shares at a weighted average exercise price of $6.65 per share and 2.9 million stock options at a weighted average
exercise price of $3.26 per share during the quarter ended March 31, 2011 and year ended December 31, 2010, respectively.

For
the quarter ended March 31, 2011 and year ended December 31, 2010, the Company recorded share-based compensation of $1.5 million and $4.5 million
respectively.

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

For the three
months ended
March 31, 2011

For the year
ended,
December 31, 2010Risk free rates


2.34 - 2.45
%

0.70 - 3.02
%Dividend yield


0
%

0
%Expected volatility


93.79 - 94.97
%

95.01 - 102.11
%Weighted average expected stock option life


6.01 years


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

$
5.13

$
2.29Total options granted


640,000


2,937,000Total weighted average fair value of options granted

$
3,285,128

$
6,732,504


13

---



Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Share-Based Payments (Continued)

A
summary of the stock options outstanding as of January 1, 2011 and March 31, 2011 is as follows:

Number
of Options

Weighted
Average
Exercise
PriceBalance outstanding at January 1, 2010


5,585,000

$
2.36Granted


2,937,000


3.26Canceled


(343,809
)

2.15Exercised


(1,688,274
)

2.13Balance outstanding at January 1, 2011


6,489,917

$
2.73Granted


640,000


6.65Canceled


(511,525
)

3.07Exercised


(866,734
)

2.89Balance outstanding at March 31, 2011


5,751,658

$
3.24Options exercisable at March 31, 2011


3,505,658

$
2.77


At
March 31, 2011, stock options outstanding were as follows:

Exercise Price

Number of Shares

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


466,000


7.75$1.01 - $2.00


895,917


3.11$2.01 - $3.00


1,128,000


8.39$3.01 - $4.00


2,069,741


5.46$4.01 - $5.00


75,000


9.61$5.01 - $6.00


120,000


9.70$6.01 - $7.20


997,000


8.635,751,658


6.55


The
aggregate intrinsic value of both outstanding and vested options as of March 31, 2011 was $20.0 million based on the Company's March 31, 2011 closing common
stock price of $6.70 per share. The total grant date fair value of the shares vested during the three months ended March 31, 2011 was $2.9 million. As of March 31, 2011, there was
$5.0 million of total unrecognized compensation cost
related to unamortized options. That cost is expected to be recognized over a period of approximately three years.

As
of March 31, 2011, there were 310,500 unvested shares of restricted stock and restricted stock units with a weighted average grant date fair value of $6.52 per share.

14

---





Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 4Share-Based Payments (Continued)

In the first quarter of 2011, the Company awarded tandem grants of 105,000 restricted stock units ("RSUs") and 52,500 performance awards ("PAs") to employees pursuant to the Company's
2007 Plan. Subject to the satisfaction of certain performance-based conditions, the RSUs and PAs vest one-quarter per year over a four year service date and the Company began recognizing
compensation expense related to these grants beginning in 2011 over the vesting period. In March 2011, the Company awarded tandem grants of 22,500 RSUs and 11,250 PAs to its Board of Directors
pursuant to the Company's 2007 Plan. The RSUs and PAs vest after a one year service date and the Company will recognize compensation expense related to these grant beginning in 2011 over the vesting
period. Total unrecognized compensation cost of $1.8 million related to non-vested
restricted stock and RSUs is expected to be recognized over a four year period. The Company recognizes compensation cost for performance based grants on a tranche level and service-based grants on a
straight-line basis over the requisite service period for the entire award. The fair value of restricted stock and RSU 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 space in Denver, Colorado and Dickinson, North Dakota under separate operating lease agreements. The Denver, Colorado lease expires on April 30, 2016.
The Dickinson, North Dakota lease expires December 31, 2013. Rent expense for the quarter ended March 31, 2011 was $87,000 and $289,000 for the year ended in 2010. The Company has no
other material capital leases and no other operating lease commitments.

The
following table shows the annual rentals per year for the life of the combined office leases:

Years ending on December 31,

(In thousands)2011

$
3382012

$
4762013

$
4902014

$
4812015

$
5022016

$
174Total

$
2,461


As
of March 31, 2011 the Company was subject to commitments on three drilling rig contracts. One of the contracts expires in late 2011, one in 2012 and the third in 2013.
Subsequent to March 31, 2011, we executed a fourth rig with a two-year drilling obligation. Rig delivery and the effective date of the contract governing the rig is expected to be
May 15, 2011. In the event of early termination under all of these contracts, the Company would be obligated to pay an aggregate amount of approximately $41.4 million as of May 5,
2011 as required under the varying terms of such contracts.

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.

The
Company may issue debt securities in the future that the Company's wholly-owned subsidiary, Kodiak Oil & Gas (USA) Inc., may guarantee. Any such guarantee is expected
to be full, unconditional and joint and several. The Company has no independent assets or operations nor does it have any

15

---



Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5Commitments and Contingencies (Continued)

other
subsidiaries. There are no significant restrictions on the ability of the Company to receive funds from the Company's subsidiary through dividends, loans, advances or otherwise.

Note 6Credit Facility

First Lien Credit Agreement

On April 13, 2011, Kodiak Oil & Gas (USA) Inc. (the "Borrower"), a wholly owned subsidiary of Kodiak Oil &
Gas Corp., entered into the Second Amendment (the "Second Amendment") to Credit Agreement with Wells Fargo Bank, N.A. ("Wells Fargo"), which amends that certain Credit Agreement (the "Credit
Agreement") between the Borrower and Wells Fargo, dated May 24, 2010, as amended by the First Amendment to Credit Agreement, dated November 30, 2010 (the "Credit Agreement").

The
Second Amendment amends the Credit Agreement to, among other things, (i) increase the borrowing base from $50,000,000 to $75,000,000; (ii) decrease the borrowing base
increase fee from 1.0% to 0.5%; (iii) reduce the commitment fee from a flat fee of 0.50% to a sliding scale of .375% to 0.50%, depending on borrowing base usage; and (iv) decrease the
interest rate through a reduction in the applicable margin applied to the alternate base or adjusted LIBO interest rates (each as defined in the Credit Agreement) payable on outstanding borrowings.
The applicable margin was reduced on the
alternate base rate from a sliding scale of 1.25% to 2.25% to a sliding scale of 0.75% to 1.75%, depending on borrowing base usage. The applicable margin was reduced on the adjusted LIBO rate from a
sliding scale of 2.25% to 3.25% to 1.75% to 2.75%, depending on borrowing base usage.

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

1.75%

2.00%

2.25%

2.50%

2.75%ABR Loans

0.75%

1.00%

1.25%

1.50%

1.75%Commitment Fee Rate

0.375%

0.375%

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 (including unused borrowing capacity) to consolidated current liabilities not less than 1.0:1.0
and a ratio of total debt to EBITDAX (as defined in the Credit Agreement) to 4.0 to 1.0 for the four fiscal quarters ending on the last day of any fiscal quarter ending on or before
December 31, 2010 and to 3.75 to 1.0 for the four fiscal quarters ending on the last day of each fiscal quarter thereafter; (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; (e) requires the Company
to maintain a ratio of EBITDAX to Interest Expense (each as defined in the Credit Agreement) of at least 3.0 to 1.0 for the four fiscal

16

---



Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6Credit Facility (Continued)

quarters
ending on the last day of any fiscal quarter and (f) limitations on the sale of property, mergers, consolidations and other similar transactions covenants. As of March 31, 2011,
the Company was in compliance with all covenants under the credit agreement. There were no borrowings under the First Lien Credit Agreement at March 31, 2011, or as of the date of this filing.

Second Lien Credit Agreement

On November 30, 2010, Kodiak Oil & Gas (USA) Inc. entered into a second lien term loan credit agreement with an
initial commitment of $40 million (the "Second Lien Credit Agreement") with Wells Fargo Energy Capital, Inc. and any other lender party thereto from time to time (collectively, the
"Lenders"). As of March 31, 2011 and December 31, 2010, the entire $40 million commitment was outstanding. Subsequent to March 31, 2011, no borrowings or repayments have
occurred under the Second Lien Credit Agreement.

Interest
on the loans under the Second Lien Credit Agreement will accrue based on one of the following two fluctuating reference rates in a manner prescribed under the applicable loan
documents: (1) the LIBOR rate (which is primarily based on the London interbank market rate), subject to a floor of 2.5% and (2) the alternate base rate (which is primarily based on
Wells Fargo's "prime" rate). Loans that accrue at the LIBOR rate, subject to the 2.5% floor, are subject to an additional margin of 8%. Loans that accrue at the alternate base rate are subject to an
additional margin of 7%. The $40 million outstanding as of March 31, 2011 under the Second Lien Credit Agreement accrues interest at 10.5%.

The
Second Lien Credit Agreement contains representations, warranties, covenants, conditions and defaults customary for transactions of this type, including but not limited to
restrictions or requirements with respect to additional debt, liens, investments, hedging activities, acquisitions, dividends, mergers, sales of assets, transactions with affiliates and capital
expenditures. In addition, the Second Lien Credit Agreement includes financial covenants substantially similar to those under the Credit Agreement, as amended by the First Amendment, and an additional
covenant addressing limitations on Subsidiary's
ratio of Total Proved PW10% to Total Debt (each as defined in the Second Lien Credit Agreement). As of March 31, 2011, the Company was in compliance with all covenants under the credit
agreement.

Interest Incurred Under the First and Second Lien Credit Agreement

For the quarter ended March 31, 2011, the Company incurred interest expense on the credit facility of $1.1 million. The
Company capitalized the entire amount of interest costs of $1.1 million for the quarter ended March 31, 2011.

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

17

---



Table of Contents

KODIAK OIL & GAS CORP.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 7Fair Value Measurements (Continued)

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 March 31, 2011 by level within the
fair value hierarchy (in thousands):

Fair Value Measurements UsingLevel 1

Level 2

Level 3

TotalLiabilities:Commodity price risk management liability





(15,094
)




(15,094
)


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 to meet its potential repayment obligations associated with the derivative
transactions. At March 31, 2011, derivative instruments utilized by the Company consist of both "no cost" collars and swaps. 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.

18

---





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 on Form 10-Q 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:



19

---



Table of Contents



Finally,
our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in the section entitled "Risk Factors" included in our
Annual Report on
Form 10-K. All forward- looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this section
and elsewhere in this 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 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.

20

---



Table of Contents

Our
revenue and future growth rate depend on factors largely beyond our control such as economic, political and regulatory developments and competition from other sources of energy. Oil
and gas prices historically have been volatile and may fluctuate widely in the future. Lower oil and natural gas prices may not only decrease our revenues, but may also reduce the amount of oil and
gas that we can produce economically and therefore could potentially lower our reserve bookings. A substantial or extended decline in oil or natural gas prices may result in impairments of our proved
oil and gas properties and may materially or adversely affect our future business, cash flows, results of operations, liquidity or ability to finance planned capital expenditures. Lower oil and gas
prices may also reduce the amount of our borrowing base under our credit agreement, which is determined at the discretion of the lenders based on the collateral value of our proved reserves that have
been mortgaged to the lenders. Alternatively, higher oil and natural gas prices have and may continue to result in significant non-cash mark-to-market losses being
recognized on our commodity derivatives, resulting in us experiencing net losses.

As
of March 31, 2011 our primary operating areas include the following:

Williston Basin

Williston Basin in Western North Dakota and Eastern Montana:As of March 31, 2011, we owned an interest in approximately 112,000
gross acres
and 70,000 net acres in this geologic basin. Our primary targets within the Williston Basin are the Bakken Pool consisting of the middle Bakken and Three Forks formations, collectively "Bakken", as
well as other formations that produce in the basin including the Mission Canyon and Red River formations. During the first quarter of 2011, we invested capital expenditures of approximately
$28.7 million related to drilling and completion operations and $4.0 million related to land leasing activities. As of March 31, 2011, we operate, or have an interest in, a total
of 36 gross (18.0 net) producing wells in the Williston Basin.

Green River Basin

Vermillion Basin of southwest Wyoming:Our primary leaseholdings in the Green River Basin are located in an area referred to as the
Vermillion Basin.
As of March 31, 2011, we owned a non-operating interest in 30,000 gross (7,000 net) acres in the Vermillion Basin that is prospective for the Baxter Shale, a
3,000-foot-thick, condensate and gas-prone interval that is also referred to as the Niobrara Shale in other parts of Wyoming and Colorado. During 2010, our partner
completed a well that has been turned to production facilities. Although we participated and were carried in the drilling, we did not participate in the completion operations. We will continue to
evaluate the play, but have not allocated capital expenditures toward the prospect during 2011.

Recent Developments

Drilling and Completion Activity

During the first quarter of 2011 we experienced delays in workover and completion operations as well as infrastructure construction due
to harsh weather conditions. Furthermore, due to weather conditions, we experienced difficulties in transporting our crude oil from the well sites, which difficulties had a negative impact on our
first quarter production. In many cases, the lack of sufficient tank storage and the constraints on oil transportation required us to shut-in our wells and production. This situation has
continued into April 2011 with heavy rainfall and melting snow pack in our production areas. However, we anticipate this situation to improve in the later part of the second quarter of 2011.

We
currently expect our production for the year to be near the lower end of our earlier guidance of 5,500 average barrels of oil equivalent per day, subject to the timely completion of
the wells scheduled to be completed in 2011. We expect our production to improve as we accelerate our program

21

---



Table of Contents

with
our third and fourth operated rigs, as weather conditions continue to improve, as the backlog of wells waiting on completions are reduced, and as we complete wells on our current
multi-well pads.

During
the first quarter of 2011, we completed one gross (0.68 net) well. In late March 2011, we began completion operations on two gross (1.9 net) wells that were placed on production
in early April. As of May 5, 2011, we have three gross (1.6 net) wells waiting to be completed, and three gross (2.0 net) wells where drilling has been completed but the wells are located on
drilling pads where we are currently drilling the final well on the pads. We expect these wells to be completed in the second and third quarters of 2011.

During
the quarter we drilled three gross (2 net) wells. Drilling operations are continuing on another two gross (1.5 net) wells. In addition, seven gross (1.7 net)
non-operated wells were spud during the first quarter of 2011.

Dedicated Fracture Stimulation Team

In the first quarter of 2011, we entered into a two-year agreement with our pressure-pumping service company whereby we
will have a dedicated crew for an
average of 14 days per month reconciled on a quarterly basis commencing in the third quarter 2011. This agreement formalizes our ongoing relationship with this service company and ensures
continuation of the close relationship we have historically maintained. As we continue to increase our drilling rig count we would anticipate that the number of days dedicated to Kodiak would also
increase.

Delivery of Third Operated Drilling Rig and Contract for Fourth Operated Drilling Rig

We are in the process of mobilizing our third operated rig onto our Smokey Prospect area in McKenzie County. We anticipate that we will
spud our first well with this rig in early May 2011. The rig was initially scheduled for delivery in the first quarter of 2011 after it completed drilling operations for another operator. However due
to drilling delays, delivery of the rig was postponed. The contract on this rig is for two years. Subsequent to March 31, 2011, we entered into a contract for a fourth operated drilling rig.
The rig is generally built to the same specification as our other three rigs, except it does not have a skid package, which we can add at a later date at our election. We intend to take delivery of
the rig during May 2011 and it will be under contract for two years. The addition of the fourth rig will allow us to accelerate our drilling program and should compensate for a portion of the drilling
days lost due to the delay of the third rig described above. The net effect to our capital budget for 2011 of adding the fourth rig, offset by delays in the first quarter of 2011 and including acreage
leasing costs to-date is an expected $20 million increase.

2011 Capital Expenditures and Budget

We have increased our 2011 capital expenditure budget by $20 million to $220 million due to the addition of a fourth
operated drilling rig and expenditures for acreage acquisition to-date. These increases were partially offset by reduced spending in the first quarter primarily as the result of the delay
in taking delivery of the third operated rig. We believe our initial budget captured anticipated cost increases and to date our well costs are meeting our expectations. We have estimated completed
well costs of $8.5 million to $9 million plus additional costs for infrastructure associated with pipeline connections. These estimates are in line with our current cost structure. We
have experienced higher costs associated with the winter months but we would expect these costs to diminish as we move into the summer operations. Our 2011 capital expenditure budget is subject to
various factors, including

22

---



Table of Contents

market
conditions, oilfield services and equipment availability, commodity prices and drilling results. Our capital budget for 2011 is comprised of the following:



Capital Resources

Our 2011 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of
capital investment. We anticipate funding the remainder of the 2011 capital program through a combination of existing working capital, our expected operating cash flows, and additional credit that may
be available under either our borrowing base or second lien term loan facilities.

As
of March 31, 2011, we have working capital of $81.8 million primarily consisting of $76.2 million of cash and equivalents. In addition, we have an existing
revolving line of credit with a borrowing base that was increased to $75.0 million in April 2011 that is currently undrawn. We expect that this borrowing base will continue to increase with the
addition of proved properties as a result of our ongoing drilling and completion activities.

We
anticipate that our operating cash flows will continue to increase as additional wells are placed on production. In the first quarter of 2011, our average sales volumes increased to
approximately 1,860 barrels of oil equivalent per day (BOEPD), or 100% over the sales volumes for the same period of 2010. Provided we complete wells that are currently awaiting completion and
that we complete new wells expected to be drilled through the remaining of 2011, and provided such wells produce at rates similar to those generated by our existing wells, we would expect our
production rates and operating cash flows to grow significantly as we move through 2011. However, there can be no assurances that we will either complete such wells or that such wells will produce or
generate cash flows at such levels.

We
cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. If
our existing and potential sources of liquidity through operating cash flows or expanded available borrowings are not sufficient to undertake our planned capital expenditures, we may be required to
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. 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 planned exploration and drilling program.

Our Properties

Williston Basin

Our primary geologic target in the Williston Basin is the middle member of the Bakken Formation, the dolomitic, sandy interval between
the two Bakken shales at an approximate vertical depth of 10,300-11,300 feet and the Three Forks Formation that is present immediately below the lower Bakken

23

---



Table of Contents

shale.
As of March 31, 2011, we were operating a two-rig program. Subsequent to March 31, 2011 we took delivery of a third drilling rig and executed a contract for a fourth
drilling rig. In addition, our joint venture partner on a portion of our Dunn County leasehold is operating one drilling rig on the lands it operates. Our working interest will vary in the wells
drilled by these non-operated rigs but we expect to have a 50% interest with respect to a significant number of the wells drilled in 2011.

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

Dunn, Mountrail and McLean Counties, North Dakota (59,000 gross and 34,000 net acres)

During 2011, we have continued to develop our Dunn County leasehold where we have consistently utilized one of our drilling rigs. We
are currently drilling the fourth well on a four-well pad. Once drilling operations are finished, this pad will be prepared for completion operations that are expected to occur during the
later part of the second quarter and the early part of the third quarter of 2011. The wells on this pad have been drilled in a manner that will continue to provide us information as to the
productivity of the Three Forks Formation as well as additional testing of wellbore density within the middle Bakken Formation and communication between the middle Bakken and Three Forks formations.

McKenzie County, North Dakota (39,000 gross and 27,000 net acres)

On our leasehold in McKenzie County, N.D., we completed two wells in early April 2011. First, the Koala
#9-5-6-12H3 (95% WI/78% NRI), an approximate 9,200-foot horizontal lateral was successfully completed in 22 stages in the Three Forks Formation. During
a 24-hour period, the well recorded production of 1,919 barrels of oil ("BO") and 2.45 million cubic feet of natural gas ("MMcf"), or 2,327 barrels of oil equivalent ("BOE"). Over
the first 21 days of production, this well produced approximately 17,900 BO and 22.9 MMcf, for an average of 1,035 BOE per day. This Three Forks well was drilled 700 feet from the middle Bakken
well discussed below in an ongoing effort to evaluate communication between the middle Bakken and the Three Forks formations. By successfully completing the Koala
#9-5-6-12H3 well, we believe we have demonstrated the productive potential of the Three Forks Formation as an oil-prone reservoir system on this part of
our McKenzie County core operating area.

In
addition, the Koala #9-5-6-5H well (95% WI/78% NRI), an approximate 9,000-foot horizontal lateral, was successfully completed in 24
stages in the middle Bakken Formation. During a 24-hour period, the well recorded production of 2,526 BO and 3.1 MMcf, or 3,042 BOE. Over the first 14 days of production, this well
produced approximately 17,000 BO and 9.3 MMcf, for an average of 1,335 BOE per day.

We
currently have two wells awaiting completion in the Koala area that were drilled on a two-well pad, the Koala #3-2-11-14H (52% WI/42%
NRI), and the Koala #3-2-11-13H (53% WI/43% NRI) wells. These two well bores have been drilled approximately 1,300 feet apart in the middle Bakken in an effort to
test well bore density within the drilling unit. These wells are projected to be completed in the second quarter of 2011.

In
February 2011, we completed the Grizzly #13-6H well in the middle Bakken Formation. This well in western McKenzie County was a reentry well where we drilled out a short
horizontal lateral of approximately 3,100 feet and fracture stimulated using 10 stages with a cemented liner. Initial

24

---



Table of Contents

production
from the well was 378 BOEPD and 128 MCF of natural gas per day or 399 BOEPD. During the first 60 days of production, the well averaged 120 BOPD.

The
following summary provides a tabular presentation of data pertinent to our Williston Basin drilling and completion activities targeting the Bakken during 2010 and 2011 (gas is
converted on a 6 Mcf to 1 barrel of oil basis):

Kodiak Oil & Gas Corp.  North Dakota (Bakken and Three Forks) Drilling and Completion Activities

IP 24-
Hour
Test
BOE/D

Daily Production (BOE/d)WI /
NRI (%)

Completion
Date

Gas / Oil
Ratio
(GOR)

Well
Status(3)Well

30 Day

60 Day

90 Day

180 Day

360 DayDunn County, ND: Longer Laterals (Over 5,000')MC #13-34-28-1H


59 / 48

Sep-10


1,906


1,082


1,074


995


723





760

FWMC #13-34-28-2H


59 / 48

Aug-10


2,055


1,259


1,073


932


655





790

FWTSB #14-21-33-15H


50 / 41

Dec-10


2,050


877
(2)

790


706








800

FWTSB #14-21-33-16H3


50 / 41

Dec-10


1,042


603


444











530

FW(1)TSB #14-21-16-2H


50 / 41

Q2 11






















WOCTSB #2-24-12-2H


50 / 41

Q2/Q3 11






















WOCSC #2-24-25-15H


96 / 79

Q2/Q3 11






















WOCTSB #2-24-12-1H3


50 / 41

Q2/Q3 11






















WOCSC #2-24-25-16H


96 / 79
























DrillingDunn County, ND: Shorter Laterals (Under 5,000')MC #16-3-11H


60 / 49

Feb-10


1,419


798


694


621


496


353


880

FWMC #16-3H


60 / 49

Mar-10


1,495


671


537


478


356





800

FWMC #13-34-3H


60 / 49

Jun-10


1,517


678


580


496


351





750

FWTSB #14-21-4H


50 / 41

Dec-10


1,196


656
(2)

470


397








750

FWMcKenzie County, NDGrizzly 13-6H


68 / 56

Feb-11


399


122


120













FWGrizzly 1-27H-R


74 / 60

Sep-10


507


210


204


196








800

PWKoala 9-5-6-5H


95 / 78

Apr-11


3,042



















FWKoala 9-5-6-12H3


95 / 78

Apr-11


2,327



















FWKoala 3-2-11-14H


52 / 42

Q2 11






















WOCKoala 3-2-11-13H


53 / 43

Q2 11






















WOCKoala 2-25-36-15H


66 / 53
























MobSmokey 15-22-15-2H


85 / 69
























Mob


(1)Only
6 out of 22 stages completed and producing(2)Production
curtailed due to weather conditions and limited crude oil transportation(3)Well
Status is as of April 30, 2011


FW = Flowing Well
PW = Pumping Well
WOC = Waiting on Completion
Mob = Rig being mobilized to well


25

---



Table of Contents

Our Leasehold

As of April 1, 2011, we had several hundred lease agreements representing approximately 157,000 gross and 90,000 net acres
primarily in the Williston and Green River Basins. The following table sets forth our gross and net acres of developed and undeveloped oil and natural gas leases:

Undeveloped
Acreage(1)

Developed
Acreage(2)

Total
AcreageGross

Net

Gross

Net

Gross

NetGreen River BasinWyoming


26,201


5,849


1,520


908


27,721


6,757Colorado


7,339


4,960


0


0


7,339


4,960Williston BasinMontana


4,938


2,874


3,240


2,446


8,178


5,320North Dakota


85,744


53,133


18,080


11,227


103,824


64,360Other BasinsWyoming


10,018


8,637


0


0


10,018


8,637Acreage Totals


134,240


75,453


22,840


14,581


157,080


90,034


(1)Undeveloped
acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage includes proved reserves.(2)Developed
acreage is the number of acres that are allocated or assignable to producing wells or wells capable of production.


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

Substantially
all of the leases summarized in the preceding table will expire at the end of their respective primary terms unless (i) the existing lease is renewed; (ii) we
have obtained production from the acreage subject to the lease prior to the end of the primary term, in which event the lease will remain in effect until the cessation of production; or
(iii) it is contained within a federal unit. The following table sets forth the gross and net acres of undeveloped land subject to leases that will expire during the next three years and have
no options for renewal or are not included in federal units:

Expiring AcreageYear Ending

Gross

NetDecember 31, 2011


5,539


3,580December 31, 2012


23,012


14,118December 31, 2013


17,112


12,206December 31, 2014


20,729


11,717Total


66,392


41,621


Operating Results

Production and Sales Volumes, Average Sales Prices, and Production Costs

The Bakken is the only field (as such term is used within the meaning of applicable regulations of the SEC) that contains more than 15%
of our total proved reserves. At December 31, 2010, this field contained 99% of our total proved reserves, nearly all of which are located in Dunn and McKenzie

26

---



Table of Contents

Counties.
The following table discloses our oil and gas production and sales volumes from the Bakken field, from our other fields combined and in total, for the periods indicated:

For the three months endedMarch 31, 2011

March 31, 2010Sales Volume (Bakken):Oil (Bbls)


149,749


71,813Gas (Mcf)


21,630


1,873Sales Volume (Other):Oil (Bbls)


7,646


5,392Gas (Mcf)


40,573


41,204Sales Volume (Total):Oil (Bbls)


157,395


77,205Gas (Mcf)


62,203


43,077Sales volumes (BOE)


167,762


84,385Natural Gas flared (Mcf)(1):


88,292


42,988Total production volume (Total):Oil (Bbls)


157,395


77,205Gas (Mcf)


150,495


86,065Production volumes (BOE)


182,477


91,549


(1)Includes
production of natural gas that is not included in our sales volumes. All flared gas is related to the Bakken field.


Sales
prices received, and production costs per sold BOE for the three months ended March 31, 2011 and 2010 are summarized in the following table:

For the three months endedMarch 31, 2011

March 31, 2010Sales Price:Gas ($/Mcf)

$
5.04

$
5.41Oil ($/Bbls)

$
82.72

$
71.08Commodity Price Risk Management Activities ($/Sales BOE):Realized loss

$
(2.04
)
$
Unrealized loss

$
(55.73
)
$
(1.45
)Production costs ($/Sales BOE):Lease operating expenses

$
5.97

$
6.53Production and property taxes

$
9.05

$
7.82Gathering, transportation, marketing

$
0.33

$
0.14


27

---





Table of Contents

Quarter Ended March 31, 2011 Compared to Quarter Ended March 31, 2010

Oil sales revenues.Oil sales revenues increased by $7.5 million to $13.0 million for the three months ended March 31,
2011, as
compared to oil sales of $5.5 million for the same period in 2010. Our oil sales volume increased 104% to 157.4 thousand barrels (MBbls) in the first quarter of 2011 as compared to 77.2
MBbls in the first quarter of 2010. The volume increase is due to the oil volumes produced from our Bakken development. However, these volumes were negatively impacted in the first quarter of 2011 by
severe winter conditions which caused delays in transportation and reduced well completion activity. Also contributing to the increase in sales revenue was the increase in the average price we
realized on the sale of our oil. Our net price received increased from $71.08 per barrel for the quarter ended March 31, 2010, to $82.72 per barrel for the quarter ended March 31, 2011.

Natural Gas sales revenues.Natural gas sales volumes increased to 62,200 Mcf in the first quarter of 2011 compared 43,100 Mcf in the
same period in
2010. The average price we realized on the sale of our natural gas was $5.04 per Mcf in the 2011 period compared to $5.41 per Mcf in 2010. The increase in our natural gas sales volumes is largely a
result of production and sales of associated gas from our Bakken properties offset by a decline of our Wyoming assets that historically contributed a majority of our natural gas production. Although
the majority of our gas from the Bakken wells to-date has been flared, late in 2010, we began connecting our wells to third party pipelines that gather and transport the gas to processing
plants and sales pipelines. We expect that a majority of our remaining wells will be connected to gas pipelines during 2011 which will allow us to capture the related sales revenue.
Industry-wide in the Williston basin, there is currently a shortage of gas gathering and processing capacity which has limited our ability to sell our gas production. During 2011, we
expect that additional third-party facilities will come online which should allow additional gas volumes to be gathered, processed and sold.

Loss on commodity price risk management activities.Primarily due to the increase in crude oil price during the first quarter of 2011,
for the three
months ended March 31, 2011, we incurred a total loss on our risk management activities of $9.7 million. This loss is a result of our hedging program used to mitigate our exposure to
commodity price fluctuations that may inhibit our ability to fund our capital expenditure budget or other obligations. This loss was comprised of approximately $342,000 of realized losses for
transactions that were settled in the first quarter of 2011 and $9.4 million of unrealized losses for the mark-to-market valuation of forward transactions. The
unrealized loss is a non-cash adjustment for the value of our risk management transactions at March 31, 2011. These transactions will continue to change in value and we will likely
add to our hedging program. Therefore we expect our net income to continue to reflect the volatility of commodity price forward markets. Our cash flows are not affected by unrealized gains and losses
on commodity risk management activities, but rather, will be affected when gains or losses are realized upon settlement of the underlying transactions at the current market prices at that time.

Oil and gas production expense.Our oil and gas production expense increased by $1.3 million to $2.6 million for the quarter
ended
March 31, 2011 as compared to the same period in 2010. The increase is due to an $861,000 increase in production taxes and a $494,000 increase in lease operating expenses ("LOE"). The
production tax increase is attributable to increased revenue as it is calculated as a fixed percentage of sales revenue. LOE increased year over year due to a higher number of wells that we operate or
participate in. On a per unit basis, LOE decreased from $6.53 per barrel sold in 2010 to $5.97 in 2011. This decrease is primarily related to increased volumes sold as compared to a lesser increase in
nominal costs. The largest cost driver in our Williston Basin operations is the disposal of flowback water used in the well completion operations. We expense the water handling costs once oil
production is established. The timing of completions and resulting water handling costs will cause variations in the LOE per barrel ratio on a quarter-to-quarter basis. To
date, this water has been transported by truck to third party disposal facilities. Late in 2010, we began connecting our wells to

28

---



Table of Contents

third
party pipelines that will transport water directly to disposal facilities. We expect that a majority of our remaining wells will be connected to water pipelines during 2011, which will
substantially reduce our water-related costs. However, we expect to continue to experience volatility relative to the timing of our well completion work.

Depletion, depreciation, amortization and abandonment liability accretion ("DDA") expense.Our depletion, depreciation, amortization
and abandonment
liability accretion expense increased by $2.4 million to $3.7 million for the three months ended March 31, 2011, from $1.3 million for the same period in 2010. This
increase is due to increased volumes sold in 2011 as sales increased by approximately 83,400 BOE over the same period. On a per unit basis, DDA increased from $15.65 per barrel sold in the first
quarter of 2010 to $22.18 per barrel sold in 2011. This increase is due to increased well costs as compared to reserves as estimated in our annual reserve report. Beginning in 2010, we have
predominantly completed our wells using a greater number of fracture stimulation stages and increased volumes of proppant. These factors have increased the well completion costs but we believe that
the higher upfront costs will generate overall higher returns through greater production volumes and total oil and gas reserves. Currently, because of the early stages of development of our Bakken
play, our reserves, especially for undeveloped locations, include the increased well costs but not the improved reserves. We believe that as our improved results are reflected in our future estimated
reserves, the DDA rate per unit will decrease over time. Also contributing to the increased DDA rate is the allocation of the purchase price to producing properties related to our acquisition in the
fourth quarter of 2010.

General and administrative ("G&A") expense.G&A expense increased by $2.6 million to $4.7 million for the quarter
ended
March 31, 2011, from $2.1 million for the same period in 2010. This increase is primarily due to the growth in personnel and related costs as we have expanded our operational
activities related to the Bakken development. Total employees increased to 40 at March 31, 2011, from 20 at March 31, 2010.

Our
G&A expense includes the non-cash expense for share-based compensation for stock options and restricted stock unit grants under our 2007 Stock Incentive Plan. For the
three months ended March 31, 2011, this expense was $1.5 million as compared to $850,000 in 2010.

Operating income.Our operating income was approximately $2.4 million for the quarter ended March 31, 2011, as compared to
approximately $1.1 million for the quarter ended March 31, 2010. This 122% increase in operating income from the first quarter of 2010 compared to the first quarter of 2011 is attributed
to our on-going successful completions of wells in our Bakken play as well as crude oil price improvement from the first quarter of 2010 to the first quarter of 2011.

Net loss.Our net loss was approximately $7.2 million for the quarter ended March 31, 2011, as compared to net income of
approximately
$1.0 million for the quarter ended March 31, 2010. Although our revenue, net of production expenses, was higher compared to 2010, our 2011 net loss was negatively impacted by increased
DDA, G&A and, most significantly, the $9.4 million unrealized loss on risk management activities discussed above.

Commitments and Contingencies

For a 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 March 31, 2011 and December 31, 2010.

29

---



Table of Contents

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,
2010, which is incorporated herein by reference.

Recently Issued Accounting Pronouncements

None.

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. The market prices for oil and natural gas have been highly
volatile and are likely to continue to be highly volatile in the future, which will impact our prospective revenues from the sale of products or properties. We manage this commodity price risk
exposure through the use of derivative financial instruments entered into with third-party counterparties. Currently, we utilize swaps and "no premium" collars to reduce the effect of price changes on
a portion of our future oil production. We do not enter into derivative instruments for trading purposes.

We
use no premium collars to establish floor and ceiling prices on our anticipated future oil production. We neither receive nor pay net premiums when we enter into these arrangements.
These contracts are settled monthly. When the settlement price (the market price for oil or natural gas on the settlement date) for a period is above the ceiling price, we pay our counterparty. When
the settlement price for a period is below the floor price, our counterparty is required to pay us. All hedges are accounted for using mark-to-market accounting.

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

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

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

30

---



Table of Contents

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

Contract Type

Counterparty

Basis(1)

Quantity(Bbl/d)

Strike Price ($/Bbl)

TermCollar

Wells Fargo Bank, N.A.

NYMEX

400

$75.00/$89.20

Jan 1 - Dec 31, 2011Collar

Wells Fargo Bank, N.A.

NYMEX

200 - 500

$70.00/$95.56

Jan 1 - Dec 31, 2011Collar

Wells Fargo Bank, N.A.

NYMEX

400

$85.00/$117.73

Mar 1 - Dec 31, 2011Collar

Wells Fargo Bank, N.A.

NYMEX

400

$70.00/$95.56

Jan 1 - Dec 31, 2012Collar

Wells Fargo Bank, N.A.

NYMEX

230

$85.00/$117.73

Jan 1 - Dec 31, 2012


Contract Type

Counterparty

Basis(1)

Quantity(Bbl/d)

Swap Price ($/Bbl)

TermSwap

Wells Fargo Bank, N.A.

NYMEX


135

$
84.00

Jan 1 - Dec 31, 2011Swap

Wells Fargo Bank, N.A.

NYMEX


130

$
90.28

Jul 1 - Dec 31, 20112011 Total/Average






201

$
85.85Swap

Wells Fargo Bank, N.A.

NYMEX


100

$
84.00

Jan 1 - Dec 31, 2012Swap

Wells Fargo Bank, N.A.

NYMEX


136

$
88.30

Jan 1 - Dec 31, 2012Swap

Wells Fargo Bank, N.A.

NYMEX


24

$
90.28

Jan 1 - Dec 31, 20122012 Total/Average






260

$
86.83Swap

Wells Fargo Bank, N.A.

NYMEX


79

$
84.00

Jan 1 - Dec 31, 2013Swap

Wells Fargo Bank, N.A.

NYMEX


427

$
88.30

Jan 1 - Dec 31, 2013Swap

Wells Fargo Bank, N.A.

NYMEX


24

$
90.28

Jan 1 - Dec 31, 20132013 Total/Average






530

$
87.75Swap

Wells Fargo Bank, N.A.

NYMEX


69

$
84.00

Jan 1 - Dec 31, 2014Swap

Wells Fargo Bank, N.A.

NYMEX


360

$
88.30

Jan 1 - Dec 31, 2014Swap

Wells Fargo Bank, N.A.

NYMEX


21

$
90.28

Jan 1 - Dec 31, 20142014 Total/Average






450

$
87.73Swap

Wells Fargo Bank, N.A.

NYMEX


59

$
84.00

Jan 1 - Oct 31, 2015Swap

Wells Fargo Bank, N.A.

NYMEX


317

$
88.30

Jan 1 - Sept 30, 2015Swap

Wells Fargo Bank, N.A.

NYMEX


46

$
90.28

Jan 1 - Oct 31, 20152015 Total/Average (Through October)






390

$
87.81


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


The following table details the fair value of the derivatives financial instruments as of March 31, 2011 and December 31, 2010, by
category (in thousands):

Underlying Commodity

Location on
Balance Sheet

March 31,
2011

December 31,
2010Crude oil derivative contract

Current liabilities

$
6,256

$
2,248Crude oil derivative contract

Noncurrent liabilities

$
8,838

$
3,495


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

ITEM 4.    CONTROLS AND PROCEDURES

Management, with the participation of our Chief Executive Officer and Chief Financial Officer, 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 March 31, 2011. On the basis of this review, our Chief
Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures

31

---



Table of Contents

are
effective to ensure 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.

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

There have been no material changes to the risk factors set forth in our Annual Report on Form 10-K for the year
ended December 31, 2010, as filed with the SEC on March 3, 2011. The risk factors in our Annual Report on Form 10-K for the year ended December 31, 2010, in
addition to the other information set forth in this quarterly report, could materially affect our business, financial condition or results of operations. Additional risks and uncertainties not
currently known to us or that we deem to be immaterial could also materially adversely affect our business, financial condition or results of operations.

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.

32

---





Table of Contents

ITEM 6.    EXHIBITS

Exhibit
Number

Description10.1

Second Amendment to Credit Agreement among Kodiak Oil & Gas (USA) Inc., Wells Fargo Bank, N.A., and the Lenders Signatory thereto, effective as of April 13, 2011 (Incorporated by reference to the Company's
Current Report on Form 8-K, filed on April 19, 2011.)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


33

---





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.May 5, 2011

/s/ LYNN A. PETERSON Lynn A. Peterson President and Chief Executive OfficerMay 5, 2011

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


34

---